ATO 2013.06.30 10-Q


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2013
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                    
Commission File Number 1-10042
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
 
Texas and Virginia
 
75-1743247
(State or other jurisdiction of
incorporation or organization)
 
(IRS employer
identification no.)
 
 
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
 
75240
(Zip code)
(Address of principal executive offices)
 
 
(972) 934-9227
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer  þ
  
Accelerated Filer  ¨
  
Non-Accelerated Filer  ¨
  
Smaller Reporting Company  ¨
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  ¨    No  þ
Number of shares outstanding of each of the issuer’s classes of common stock, as of August 2, 2013.
Class
  
Shares Outstanding
No Par Value
  
90,640,211




GLOSSARY OF KEY TERMS
 
 
 
AEC
Atmos Energy Corporation
AEH
Atmos Energy Holdings, Inc.
AEM
Atmos Energy Marketing, LLC
AOCI
Accumulated other comprehensive income
APS
Atmos Pipeline and Storage, LLC
Bcf
Billion cubic feet
CFTC
Commodity Futures Trading Commission
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings, Ltd.
GAAP
Generally Accepted Accounting Principles
GRIP
Gas Reliability Infrastructure Program
GSRS
Gas System Reliability Surcharge
Mcf
Thousand cubic feet
MMcf
Million cubic feet
Moody’s
Moody’s Investors Services, Inc.
NYMEX
New York Mercantile Exchange, Inc.
PPA
Pension Protection Act of 2006
PRP
Pipeline Replacement Program
RRC
Railroad Commission of Texas
RRM
Rate Review Mechanism
S&P
Standard & Poor’s Corporation
SEC
United States Securities and Exchange Commission
WNA
Weather Normalization Adjustment

2



PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 
June 30, 2013
 
September 30, 2012
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
7,494,175

 
$
7,134,470

Less accumulated depreciation and amortization
1,652,960

 
1,658,866

Net property, plant and equipment
5,841,215

 
5,475,604

Current assets
 
 
 
Cash and cash equivalents
31,979

 
64,239

Accounts receivable, net
350,237

 
234,526

Gas stored underground
209,101

 
256,415

Other current assets
90,936

 
272,782

Total current assets
682,253

 
827,962

Goodwill and intangible assets
740,814

 
740,847

Deferred charges and other assets
538,516

 
451,262

 
$
7,802,798

 
$
7,495,675

CAPITALIZATION AND LIABILITIES
 
 
 
Shareholders’ equity
 
 
 
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: June 30, 2013 — 90,639,520 shares; September 30, 2012 — 90,239,900 shares
$
453

 
$
451

Additional paid-in capital
1,757,059

 
1,745,467

Retained earnings
800,643

 
660,932

Accumulated other comprehensive income (loss)
23,289

 
(47,607
)
Shareholders’ equity
2,581,444

 
2,359,243

Long-term debt
2,455,593

 
1,956,305

Total capitalization
5,037,037

 
4,315,548

Current liabilities
 
 
 
Accounts payable and accrued liabilities
229,876

 
215,229

Other current liabilities
348,706

 
489,665

Short-term debt
141,998

 
570,929

Current maturities of long-term debt

 
131

Total current liabilities
720,580

 
1,275,954

Deferred income taxes
1,197,274

 
1,015,083

Regulatory cost of removal obligation
360,578

 
381,164

Pension and postretirement liabilities
444,540

 
457,196

Deferred credits and other liabilities
42,789

 
50,730

 
$
7,802,798

 
$
7,495,675

See accompanying notes to condensed consolidated financial statements.

3



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 June 30
 
2013
 
2012
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Natural gas distribution segment
$
467,144

 
$
315,634

Regulated transmission and storage segment
74,041

 
67,073

Nonregulated segment
421,808

 
256,250

Intersegment eliminations
(105,058
)
 
(62,543
)
 
857,935

 
576,414

Purchased gas cost
 
 
 
Natural gas distribution segment
227,649

 
120,575

Regulated transmission and storage segment

 

Nonregulated segment
418,548

 
224,829

Intersegment eliminations
(104,759
)
 
(62,161
)
 
541,438

 
283,243

Gross profit
316,497

 
293,171

Operating expenses
 
 
 
Operation and maintenance
121,258

 
106,045

Depreciation and amortization
58,129

 
58,956

Taxes, other than income
50,714

 
46,624

Total operating expenses
230,101

 
211,625

Operating income
86,396

 
81,546

Miscellaneous expense
(467
)
 
(2,075
)
Interest charges
32,741

 
34,909

Income from continuing operations before income taxes
53,188

 
44,562

Income tax expense
19,714

 
16,548

Income from continuing operations
33,474

 
28,014

Income from discontinued operations, net of tax ($0 and $1,792)

 
3,118

Gain on sale of discontinued operations, net of tax ($2,909 and $0)
5,294

 

Net income
$
38,768

 
$
31,132

Basic earnings per share
 
 
 
Income per share from continuing operations
$
0.37

 
$
0.31

Income per share from discontinued operations
0.06

 
0.03

Net income per share — basic
$
0.43

 
$
0.34

Diluted earnings per share
 
 
 
Income per share from continuing operations
$
0.36

 
$
0.31

Income per share from discontinued operations
0.06

 
0.03

Net income per share — diluted
$
0.42

 
$
0.34

Cash dividends per share
$
0.350

 
$
0.345

Weighted average shares outstanding:
 
 
 
Basic
90,603

 
90,118

Diluted
91,550

 
90,993

See accompanying notes to condensed consolidated financial statements.

4




ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Natural gas distribution segment
$
2,039,107

 
$
1,862,814

Regulated transmission and storage segment
196,570

 
181,869

Nonregulated segment
1,250,650

 
1,071,189

Intersegment eliminations
(285,241
)
 
(229,955
)
 
3,201,086

 
2,885,917

Purchased gas cost
 
 
 
Natural gas distribution segment
1,172,975

 
1,011,832

Regulated transmission and storage segment

 

Nonregulated segment
1,200,624

 
1,028,592

Intersegment eliminations
(284,123
)
 
(228,857
)
 
2,089,476

 
1,811,567

Gross profit
1,111,610

 
1,074,350

Operating expenses
 
 
 
Operation and maintenance
338,871

 
329,989

Depreciation and amortization
174,888

 
176,742

Taxes, other than income
146,355

 
144,170

Total operating expenses
660,114

 
650,901

Operating income
451,496

 
423,449

Miscellaneous income (expense)
1,943

 
(3,585
)
Interest charges
96,594

 
107,278

Income from continuing operations before income taxes
356,845

 
312,586

Income tax expense
133,683

 
120,104

Income from continuing operations
223,162

 
192,482

Income from discontinued operations, net of tax ($3,986 and $9,339)
7,202

 
16,268

Gain on sale of discontinued operations, net of tax ($2,909 and $0)
5,294

 

Net income
$
235,658

 
$
208,750

Basic earnings per share
 
 
 
Income per share from continuing operations
$
2.46

 
$
2.13

Income per share from discontinued operations
0.14

 
0.18

Net income per share — basic
$
2.60

 
$
2.31

Diluted earnings per share
 
 
 
Income per share from continuing operations
$
2.43

 
$
2.10

Income per share from discontinued operations
0.14

 
0.18

Net income per share — diluted
$
2.57

 
$
2.28

Cash dividends per share
$
1.050

 
$
1.035

Weighted average shares outstanding:
 
 
 
Basic
90,497

 
90,131

Diluted
91,445

 
91,006

See accompanying notes to condensed consolidated financial statements.

5




ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(Unaudited)
(In thousands)
Net income
$
38,768

 
$
31,132

 
$
235,658

 
$
208,750

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(202), $(523), $(532) and $1,194
(348
)
 
(888
)
 
(921
)
 
2,059

Cash flow hedges:
 
 
 
 
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $17,865, $(18,399), $38,427 and $(9,995)
31,079

 
(31,328
)
 
66,852

 
(17,019
)
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $(2,243), $11,401, $3,174 and $(2,595)
(3,508
)
 
17,830

 
4,965

 
(4,060
)
Total other comprehensive income (loss)
27,223

 
(14,386
)
 
70,896

 
(19,020
)
Total comprehensive income
$
65,991

 
$
16,746

 
$
306,554

 
$
189,730


See accompanying notes to condensed consolidated financial statements.

6



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
235,658

 
$
208,750

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Gain on sale of discontinued operations
(8,203
)
 

Depreciation and amortization:
 
 
 
Charged to depreciation and amortization
176,737

 
183,884

Charged to other accounts
446

 
310

Deferred income taxes
130,365

 
120,713

Other
14,460

 
22,386

Net assets / liabilities from risk management activities
(6,386
)
 
12,759

Net change in operating assets and liabilities
(33,502
)
 
(29,996
)
Net cash provided by operating activities
509,575

 
518,806

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(582,473
)
 
(497,374
)
Proceeds from the sale of discontinued operations
153,023

 

Other, net
(3,139
)
 
(4,247
)
Net cash used in investing activities
(432,589
)
 
(501,621
)
Cash Flows From Financing Activities
 
 
 
Net decrease in short-term debt
(435,084
)
 
(6,688
)
Net proceeds from issuance of long-term debt
493,793

 

Settlement of Treasury lock agreements
(66,626
)
 

Repayment of long-term debt
(131
)
 
(2,369
)
Cash dividends paid
(96,060
)
 
(94,338
)
Repurchase of common stock

 
(12,535
)
Repurchase of equity awards
(5,146
)
 
(5,219
)
Issuance of common stock
8

 
251

Net cash used in financing activities
(109,246
)
 
(120,898
)
Net decrease in cash and cash equivalents
(32,260
)
 
(103,713
)
Cash and cash equivalents at beginning of period
64,239

 
131,419

Cash and cash equivalents at end of period
$
31,979

 
$
27,706


See accompanying notes to condensed consolidated financial statements.

7



ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2013
1.    Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. For the fiscal year ended September 30, 2012, our regulated businesses generated over 95 percent of our consolidated net income.
Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions, which at June 30, 2013, covered service areas located in eight states. In addition, we transport natural gas for others through our distribution system. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers. Our regulated businesses also include our regulated pipeline and storage operations, which include the transportation of natural gas to our distribution system and the management of our underground storage facilities. Our regulated businesses are subject to federal and state regulation and/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate.
Our nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc., (AEH). AEH is wholly owned by the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, natural gas distribution companies, including certain divisions of Atmos Energy and third parties.
We operate the Company through the following three segments:
the natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and
the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
2.    Unaudited Financial Information
These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. Because of seasonal and other factors, the results of operations for the nine-month period ended June 30, 2013 are not indicative of our results of operations for the full 2013 fiscal year, which ends September 30, 2013.
We have evaluated subsequent events from the June 30, 2013 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). Except as noted in Note 10, no events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

Significant accounting policies
Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012.
During the second quarter of fiscal 2013, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.
Due to the April 1, 2013 sale of our Georgia distribution operations, at June 30, 2013, the financial results for this service area are shown in discontinued operations. Accordingly, certain prior-year amounts have been reclassified to conform with the current-year presentation.
During the nine months ended June 30, 2013, two new accounting standards were announced that will become applicable to the Company in future periods. The first standard clarifies the enhanced disclosure of offsetting arrangements for financial instruments that will become effective for us for annual and interim periods beginning on October 1, 2013. The adoption of this standard should not have an impact on our financial position, results of operations or cash flows. The second standard, which became effective during our second fiscal quarter, requires the presentation of amounts reclassified out of accumulated other

8



comprehensive income by component as well as significant amounts reclassified out of accumulated other comprehensive income by the respective line item in the statement of net income. We have presented the disclosures relating to reclassifications out of accumulated other comprehensive income in Note 4. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the nine months ended June 30, 2013.
Regulatory assets and liabilities
Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.
 
Significant regulatory assets and liabilities as of June 30, 2013 and September 30, 2012 included the following:
 
June 30,
2013
 
September 30,
2012
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
280,136

 
$
296,160

Merger and integration costs, net
5,376

 
5,754

Deferred gas costs
1,271

 
31,359

Regulatory cost of removal asset
6,058

 
10,500

Rate case costs
6,207

 
4,661

Deferred franchise fees
242

 
2,714

Texas Rule 8.209(2)
21,351

 
5,370

APT annual adjustment mechanism
5,167

 
4,539

Other
1,935

 
7,262

 
$
327,743

 
$
368,319

Regulatory liabilities:
 
 
 
Deferred gas costs
$
30,773

 
$
23,072

Deferred franchise fees
2,097

 

Regulatory cost of removal obligation
426,656

 
459,688

Other
5,398

 
5,637

 
$
464,924

 
$
488,397

 
(1) 
Includes $15.5 million and $7.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.
(2) 
Texas Rule 8.209 is a Railroad Commission rule that allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.
The amounts above do not include regulatory assets and liabilities related to our Georgia operations, which were classified as assets held for sale at September 30, 2012 as discussed in Note 6. As of June 30, 2013 we did not have any assets or liabilities classified as held for sale due to the sale of substantially all of our Georgia assets on April 1, 2013.
Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years.

9



3.    Financial Instruments
We use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. The accounting for these financial instruments is fully described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. During the nine months ended June 30, 2013 there were no changes in our objectives, strategies and accounting for these financial instruments. Currently, we utilize financial instruments in our natural gas distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.
 
Our financial instruments do not contain any credit-risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions.
Regulated Commodity Risk Management Activities
Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2012-2013 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or 22.8 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.
The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with applicable authoritative accounting guidance. Accordingly, there is no earnings impact on our natural gas distribution segment as a result of the use of financial instruments.
Nonregulated Commodity Risk Management Activities
Our nonregulated operations aggregate and purchase gas supply, arrange transportation and/or storage logistics and ultimately deliver gas to our customers at competitive prices. To provide these services, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request. In an effort to offset the demand fees paid to contract for storage capacity and to maximize the value of this capacity, AEH sells financial instruments to earn a gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.
As a result of these activities, our nonregulated segment is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange traded options and swap contracts with counterparties. Future contracts provide the right, but not the obligation, to buy or sell the commodity at a fixed price. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.
We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our nonregulated operations associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 58 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in asset optimization activities in our nonregulated segment.
 
Our nonregulated operations also use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges for accounting purposes.

10



Interest Rate Risk Management Activities
We have periodically managed interest rate risk by entering into financial instruments to fix the Treasury yield component of the interest cost associated with anticipated financings. Prior to fiscal 2012, we used only Treasury locks to mitigate interest rate risk; however, beginning in the fourth quarter of fiscal 2012 we started utilizing interest rate swaps and forward starting interest rate swaps to manage this risk.
In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $350 million out of a total $500 million of senior notes that were issued on January 11, 2013. This offering is discussed in Note 7. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on January 8, 2013 with a payment of $66.6 million to the counterparties due to a decrease in the 30-year Treasury rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the $66.6 million unrealized loss was recorded as a component of accumulated other comprehensive income and is being recognized as a component of interest expense over the 30-year life of the senior notes.
In the fourth quarter of fiscal 2012, we entered into an interest rate swap to fix the LIBOR component of our $260 million short-term financing facility that terminated on December 27, 2012. We recorded an immaterial loss upon settlement of the swap, which was recorded as a component of interest expense as we did not designate the interest rate swap as a hedge.
In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the anticipated issuance of $500 million and $250 million unsecured senior notes in fiscal 2015 and fiscal 2017, which we designated as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the forward starting interest rate swaps are being recorded as a component of accumulated other comprehensive income (loss). When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred is reported as a component of interest expense.
In prior years, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes. The gains and losses realized upon settlement of these Treasury locks were recorded as a component of accumulated other comprehensive income (loss) when they were settled and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. As of June 30, 2013, the remaining amortization periods for the settled Treasury locks extend through fiscal 2043.
 
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
As of June 30, 2013, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of June 30, 2013, we had net long/(short) commodity contracts outstanding in the following quantities:
Contract Type
 
Hedge Designation
 
Natural Gas
Distribution
 
Nonregulated
 
 
 
 
Quantity (MMcf)
Commodity contracts
 
Fair Value
 

 
(22,250
)
 
 
Cash Flow
 

 
26,520

 
 
Not designated
 
14,649

 
75,520

 
 
 
 
14,649

 
79,790

Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of June 30, 2013 and September 30, 2012. As required by authoritative accounting literature, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include $14.3 million and $23.7 million of cash held on deposit in margin accounts as of June 30, 2013 and September 30, 2012 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not be equal to the amounts presented on our condensed consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 5.

11



 
Balance Sheet Location
 
Natural Gas
Distribution
 
Nonregulated
 
Total
 
 
 
 
 
(In thousands)
 
 
June 30, 2013
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
Asset Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current assets
 
$

 
$
12,250

 
$
12,250

Noncurrent commodity contracts
Deferred charges and other assets
 
84,432

 
401

 
84,833

Liability Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current liabilities
 

 
(13,771
)
 
(13,771
)
Noncurrent commodity contracts
Deferred credits and other liabilities
 

 
(1,912
)
 
(1,912
)
Total
 
 
84,432

 
(3,032
)
 
81,400

Not Designated As Hedges:
 
 
 
 
 
 
 
Asset Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current assets
 
2,015

 
68,972

 
70,987

Noncurrent commodity contracts
Deferred charges and other assets
 
1,035

 
49,651

 
50,686

Liability Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current liabilities
 
(1,094
)
 
(69,710
)
 
(70,804
)
Noncurrent commodity contracts
Deferred credits and other liabilities
 

 
(50,204
)
 
(50,204
)
Total
 
 
1,956

 
(1,291
)
 
665

Total Financial Instruments
 
 
$
86,388

 
$
(4,323
)
 
$
82,065

 
 
 
Balance Sheet Location
 
Natural Gas
Distribution
 
Nonregulated
 
Total
 
 
 
 
 
(In thousands)
 
 
September 30, 2012
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
Asset Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current assets
 
$

 
$
19,301

 
$
19,301

Noncurrent commodity contracts
Deferred charges and other assets
 

 
1,923

 
1,923

Liability Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current liabilities
 
(85,040
)
 
(23,787
)
 
(108,827
)
Noncurrent commodity contracts
Deferred credits and other liabilities
 

 
(4,999
)
 
(4,999
)
Total
 
 
(85,040
)
 
(7,562
)
 
(92,602
)
Not Designated As Hedges:
 
 
 
 
 
 
 
Asset Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current assets(1)
 
7,082

 
98,393

 
105,475

Noncurrent commodity contracts
Deferred charges and other assets
 
2,283

 
60,932

 
63,215

Liability Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current liabilities(2)
 
(585
)
 
(99,824
)
 
(100,409
)
Noncurrent commodity contracts
Deferred credits and other liabilities
 

 
(67,062
)
 
(67,062
)
Total
 
 
8,780

 
(7,561
)
 
1,219

Total Financial Instruments
 
 
$
(76,260
)
 
$
(15,123
)
 
$
(91,383
)
 
(1) 
Other current assets not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management assets that were classified as assets held for sale at September 30, 2012.
(2) 
Other current liabilities not designated as hedges in our natural gas distribution segment include $0.3 million related to risk management liabilities that were classified as liabilities held for sale at September 30, 2012.

12



Impact of Financial Instruments on the Income Statement
Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended June 30, 2013 and 2012 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $(0.4) million and $19.0 million. For the nine months ended June 30, 2013 and 2012 we recognized gains arising from fair value and cash flow hedge ineffectiveness of $17.3 million and $21.2 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 
Fair Value Hedges
The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and nine months ended June 30, 2013 and 2012 is presented below.
 
Three Months Ended 
 June 30
 
2013
 
2012
 
(In thousands)
Commodity contracts
$
14,453

 
$
(14,942
)
Fair value adjustment for natural gas inventory designated as the hedged item
(15,143
)
 
34,296

Total (increase) decrease in purchased gas cost
$
(690
)
 
$
19,354

The (increase) decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
(2,361
)
 
$
2,077

Timing ineffectiveness
1,671

 
17,277

 
$
(690
)
 
$
19,354

 
Nine Months Ended 
 June 30
 
2013
 
2012
 
(In thousands)
Commodity contracts
$
3,921

 
$
38,211

Fair value adjustment for natural gas inventory designated as the hedged item
13,261

 
(16,039
)
Total decrease in purchased gas cost
$
17,182

 
$
22,172

The decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
(1,143
)
 
$
2,179

Timing ineffectiveness
18,325

 
19,993

 
$
17,182

 
$
22,172

Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost.
To the extent that the Company’s natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market. We did not record a writedown for nonqualifying natural gas inventory for the nine months ended June 30, 2013. During the nine months ended June 30, 2012, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market.

Cash Flow Hedges
The impact of cash flow hedges on our condensed consolidated income statements for the three and nine months ended June 30, 2013 and 2012 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

13



 
Three Months Ended June 30, 2013
 
Natural
Gas
Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts
$

 
$
558

 
$
558

Gain arising from ineffective portion of commodity contracts

 
260

 
260

Total impact on purchased gas cost

 
818

 
818

Loss on settled interest rate agreements reclassified from AOCI into interest expense
(1,057
)
 

 
(1,057
)
Total Impact from Cash Flow Hedges
$
(1,057
)
 
$
818

 
$
(239
)
 
Three Months Ended June 30, 2012
 
Natural
Gas
Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$

 
$
(19,534
)
 
$
(19,534
)
Loss arising from ineffective portion of commodity contracts

 
(328
)
 
(328
)
Total impact on purchased gas cost

 
(19,862
)
 
(19,862
)
Loss on settled interest rate agreements reclassified from AOCI into interest expense
(502
)
 

 
(502
)
Total Impact from Cash Flow Hedges
$
(502
)
 
$
(19,862
)
 
$
(20,364
)
 
Nine Months Ended June 30, 2013
 
Natural
Gas
Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$

 
$
(9,802
)
 
$
(9,802
)
Gain arising from ineffective portion of commodity contracts

 
158

 
158

Total impact on purchased gas cost

 
(9,644
)
 
(9,644
)
Loss on settled interest rate agreements reclassified from AOCI into interest expense
(2,432
)
 

 
(2,432
)
Total Impact from Cash Flow Hedges
$
(2,432
)
 
$
(9,644
)
 
$
(12,076
)
 
 
Nine Months Ended June 30, 2012
 
Natural Gas
Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$

 
$
(52,358
)
 
$
(52,358
)
Loss arising from ineffective portion of commodity contracts

 
(996
)
 
(996
)
Total impact on purchased gas cost

 
(53,354
)
 
(53,354
)
Loss on settled interest rate agreements reclassified from AOCI into interest expense
(1,506
)
 

 
(1,506
)
Total Impact from Cash Flow Hedges
$
(1,506
)
 
$
(53,354
)
 
$
(54,860
)
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and nine months ended June 30, 2013 and 2012. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.

14



 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
 
 
 
 
Interest rate agreements
$
30,408

 
$
(31,644
)
 
$
65,308

 
$
(17,968
)
Forward commodity contracts
(3,168
)
 
5,914

 
(1,015
)
 
(35,998
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
 
 
 
 
Interest rate agreements
671

 
316

 
1,544

 
949

Forward commodity contracts
(340
)
 
11,916

 
5,980

 
31,938

Total other comprehensive income (loss) from hedging, net of tax(1)
$
27,571

 
$
(13,498
)
 
$
71,817

 
$
(21,079
)
 
(1) 
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
Deferred gains (losses) recorded in accumulated other comprehensive income (AOCI) associated with our interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, while deferred losses associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of June 30, 2013. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those instruments have not yet settled.
 
Interest Rate
Agreements
 
Commodity
Contracts
 
Total
 
(In thousands)
Next twelve months
$
(2,686
)
 
$
(3,133
)
 
$
(5,819
)
Thereafter
(28,350
)
 
(897
)
 
(29,247
)
Total(1) 
$
(31,036
)
 
$
(4,030
)
 
$
(35,066
)
 
(1) 
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
 
Financial Instruments Not Designated as Hedges
The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three months ended June 30, 2013 and 2012 was an increase (decrease) in gross profit of $(8.4) million and $11.2 million. For the nine months ended June 30, 2013 and 2012 gross profit decreased $1.7 million and $3.8 million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact on our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.
4.    Accumulated Other Comprehensive Income
We record deferred gains (losses) in accumulated other comprehensive income (AOCI) related to available-for-sale securities, interest rate agreement cash flow hedges and commodity contract cash flow hedges. Deferred gains (losses) for our available-for-sale securities and commodity contract cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as they are amortized. The following table provides the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income.

15



 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Commodity
Contracts
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2012
$
5,661

 
$
(44,273
)
 
$
(8,995
)
 
$
(47,607
)
Other comprehensive income before reclassifications
449

 
65,308

 
(1,015
)
 
64,742

Amounts reclassified from accumulated other comprehensive income
(1,370
)
 
1,544

 
5,980

 
6,154

Net current-period other comprehensive income
(921
)
 
66,852

 
4,965

 
70,896

June 30, 2013
$
4,740

 
$
22,579

 
$
(4,030
)
 
$
23,289

 
The following tables detail reclassifications out of AOCI for the three and nine months ended June 30, 2013. Amounts in parentheses below indicate decreases to net income in the statement of income.
 
Three Months Ended June 30, 2013
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
(531
)
 
Operation and maintenance expense
 
(531
)
 
Total before tax
 
193

 
Tax benefit
 
$
(338
)
 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(1,057
)
 
Interest charges
Commodity contracts
558

 
Purchased gas cost
 
(499
)
 
Total before tax
 
168

 
Tax benefit
 
$
(331
)
 
Net of tax
Total reclassifications
$
(669
)
 
Net of tax
 
Nine Months Ended June 30, 2013
Accumulated Other Comprehensive Income Components                          
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in  the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
2,158

 
Operation and maintenance expense
 
2,158

 
Total before tax
 
(788
)
 
Tax expense
 
$
1,370

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(2,432
)
 
Interest charges
Commodity contracts
(9,803
)
 
Purchased gas cost
 
(12,235
)
 
Total before tax
 
4,711

 
Tax benefit
 
$
(7,524
)
 
Net of tax
Total reclassifications
$
(6,154
)
 
Net of tax
5.    Fair Value Measurements
We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair

16



value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. During the three and nine months ended June 30, 2013, there were no changes in these methods.
Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 9 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2012.
Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 and September 30, 2012. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral(2)
 
June 30, 2013
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Natural gas distribution segment
$

 
$
87,482

 
$

 
$

 
$
87,482

Nonregulated segment
1,196

 
130,078

 

 
(119,278
)
 
11,996

Total financial instruments
1,196

 
217,560

 

 
(119,278
)
 
99,478

Hedged portion of gas stored underground
76,706

 

 

 

 
76,706

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Money market funds

 
5,122

 

 

 
5,122

Registered investment companies
39,051

 

 

 

 
39,051

Bonds

 
27,473

 

 

 
27,473

Total available-for-sale securities
39,051

 
32,595

 

 

 
71,646

Total assets
$
116,953

 
$
250,155

 
$

 
$
(119,278
)
 
$
247,830

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Natural gas distribution segment
$

 
$
1,094

 
$

 
$

 
$
1,094

Nonregulated segment
179

 
135,418

 

 
(133,530
)
 
2,067

Total liabilities
$
179

 
$
136,512

 
$

 
$
(133,530
)
 
$
3,161


17



 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral(3)
 
September 30, 2012
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Natural gas distribution segment
$

 
$
9,365

 
$

 
$

 
$
9,365

Nonregulated segment
714

 
179,835

 

 
(162,776
)
 
17,773

Total financial instruments
714

 
189,200

 

 
(162,776
)
 
27,138

Hedged portion of gas stored underground
67,192

 

 

 

 
67,192

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Money market funds

 
1,634

 

 

 
1,634

Registered investment companies
40,212

 

 

 

 
40,212

Bonds

 
22,552

 

 

 
22,552

Total available-for-sale securities
40,212

 
24,186

 

 

 
64,398

Total assets
$
108,118

 
$
213,386

 
$

 
$
(162,776
)
 
$
158,728

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Natural gas distribution segment
$

 
$
85,625

 
$

 
$

 
$
85,625

Nonregulated segment
4,563

 
191,109

 

 
(186,451
)
 
9,221

Total liabilities
$
4,563

 
$
276,734

 
$

 
$
(186,451
)
 
$
94,846

 
(1) 
Our Level 2 measurements consist of over-the-counter options and swaps which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.
(2) 
This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of June 30, 2013, we had $14.3 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $2.5 million was used to offset current risk management liabilities under master netting arrangements and the remaining $11.8 million is classified as current risk management assets.
(3) 
This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2012 we had $23.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.
 

18



Available-for-sale securities are comprised of the following:
 
Amortized
Cost
 
Gross
Unrealized
Gain
 
Gross
Unrealized
Loss
 
Fair
Value
 
(In thousands)
As of June 30, 2013
 
 
 
 
 
 
 
Domestic equity mutual funds
$
26,993

 
$
6,611

 
$

 
$
33,604

Foreign equity mutual funds
4,536

 
925

 
(14
)
 
5,447

Bonds
27,390

 
132

 
(49
)
 
27,473

Money market funds
5,122

 

 

 
5,122

 
$
64,041

 
$
7,668

 
$
(63
)
 
$
71,646

As of September 30, 2012
 
 
 
 
 
 
 
Domestic equity mutual funds
$
25,779

 
$
8,183

 
$

 
$
33,962

Foreign equity mutual funds
5,568

 
682

 

 
6,250

Bonds
22,358

 
196

 
(2
)
 
22,552

Money market funds
1,634

 

 

 
1,634

 
$
55,339

 
$
9,061

 
$
(2
)
 
$
64,398

At June 30, 2013 and September 30, 2012, our available-for-sale securities included $44.2 million and $41.8 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At June 30, 2013, we maintained investments in bonds that have contractual maturity dates ranging from July 2013 through December 2019. During the nine months ended June 30, 2013, we recognized a net gain of $2.2 million on the sale of certain assets in the rabbi trusts.
These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.
Other Fair Value Measures
Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of June 30, 2013:
 
June 30, 2013
 
(In thousands)
Carrying Amount
$
2,460,000

Fair Value
$
2,707,340


6.    Discontinued Operations
On April 1, 2013, we completed the sale of substantially all of our natural gas distribution assets and certain related nonregulated assets located in Georgia to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million. The sale was previously announced on August 8, 2012. In connection with the sale, we recognized a net of tax gain of $5.3 million.
As required under generally accepted accounting principles, the operating results of our Georgia operations have been aggregated and reported on the condensed consolidated statements of income as income from discontinued operations, net of income tax. For the three months ended June 30, 2013, net income from discontinued operations includes the aforementioned gain on sale, while for the nine months ended June 30, 2013, net income from discontinued operations includes the operating results of our Georgia operations and the gain on sale. For the three and nine months ended June 30, 2012, net income from discontinued operations includes the operating results of our Georgia operations and the operating results of our Missouri, Illinois and Iowa operations that were sold on August 1, 2012. Expenses related to general corporate overhead and interest expense allocated to their operations are not included in discontinued operations.

19



The tables below set forth selected financial and operational information related to net assets and operating results related to discontinued operations. Additionally, assets and liabilities related to our Georgia operations are classified as “held for sale” in other current assets and liabilities in our condensed consolidated balance sheets at September 30, 2012. Prior period revenues and expenses associated with these assets have been reclassified into discontinued operations. This reclassification had no impact on previously reported net income.
The following table presents statement of income data related to discontinued operations.
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Operating revenues
$

 
$
18,162

 
$
37,962

 
$
103,107

Purchased gas cost

 
6,803

 
21,464

 
57,936

Gross profit

 
11,359

 
16,498

 
45,171

Operating expenses

 
6,522

 
5,858

 
20,069

Operating income

 
4,837

 
10,640

 
25,102

Other nonoperating income

 
73

 
548

 
505

Income from discontinued operations before income taxes

 
4,910

 
11,188

 
25,607

Income tax expense

 
1,792

 
3,986

 
9,339

Income from discontinued operations

 
3,118

 
7,202

 
16,268

Gain on sale of discontinued operations, net of tax
5,294

 

 
5,294

 

Net income from discontinued operations
$
5,294

 
$
3,118

 
$
12,496

 
$
16,268


The following table presents balance sheet data related to assets held for sale. At September 30, 2012 assets held for sale include assets and liabilities associated with our Georgia operations. At June 30, 2013 we did not have any assets or liabilities held for sale.
 
September 30, 2012
 
(In thousands)
Net plant, property & equipment
$
142,865

Gas stored underground
4,688

Other current assets
6,931

Deferred charges and other assets
87

Assets held for sale
$
154,571

 
 
Accounts payable and accrued liabilities
$
2,114

Other current liabilities
3,776

Regulatory cost of removal
3,257

Deferred credits and other liabilities
2,426

Liabilities held for sale
$
11,573


7.    Debt
The nature and terms of our debt instruments and credit facilities are described in detail in Note 7 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. Except as noted below, there were no material changes in the terms of our debt instruments during the nine months ended June 30, 2013.
Long-term debt
Long-term debt at June 30, 2013 and September 30, 2012 consisted of the following:
 

20



 
June 30, 2013
 
September 30, 2012
 
(In thousands)
Unsecured 4.95% Senior Notes, due October 2014
$
500,000

 
$
500,000

Unsecured 6.35% Senior Notes, due 2017
250,000

 
250,000

Unsecured 8.50% Senior Notes, due 2019
450,000

 
450,000

Unsecured 5.95% Senior Notes, due 2034
200,000

 
200,000

Unsecured 5.50% Senior Notes, due 2041
400,000

 
400,000

Unsecured 4.15% Senior Notes, due 2043
500,000

 

Medium term note Series A, 1995-1, 6.67%, due 2025
10,000

 
10,000

Unsecured 6.75% Debentures, due 2028
150,000

 
150,000

Rental property term note due in installments through 2013

 
131

Total long-term debt
2,460,000

 
1,960,131

Less:
 
 
 
Original issue discount on unsecured senior notes and debentures
4,407

 
3,695

Current maturities

 
131

 
$
2,455,593

 
$
1,956,305

 
Our $250 million Unsecured 5.125% Senior Notes were originally scheduled to mature in January 2013. On August 28, 2012 we redeemed these notes with proceeds received through the issuance of commercial paper. On September 27, 2012, we entered into a $260 million short-term financing facility that was scheduled to mature on February 1, 2013 to repay the commercial paper borrowings utilized to redeem the Unsecured 5.125% Senior Notes. The short-term facility was repaid with the proceeds received through the issuance of 30-year unsecured senior notes on January 11, 2013, as discussed below.
We issued $500 million Unsecured 4.15% Senior Notes on January 11, 2013. The effective interest rate of these notes is 4.64 percent, after giving effect to offering costs and the settlement of the associated Treasury lock agreements discussed in Note 3. Of the net proceeds of approximately $494 million, $260 million was used to repay our short-term financing facility. The remaining $234 million of net proceeds was used to partially repay our commercial paper borrowings and for general corporate purposes.
Short-term debt
Our short-term debt is utilized to fund ongoing working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity and capital expenditures. Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings typically reach their highest levels in the winter months.
We currently finance our short-term borrowing requirements through a combination of a $750 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. On December 7, 2012, we amended the terms of our former $750 million unsecured credit facility to increase the borrowing capacity to $950 million, with an accordion feature, which, if utilized, would increase the borrowing capacity to $1.2 billion. The amendment also permits us to obtain same-day funding on base rate loans. There were no other material changes to the credit facility. These facilities provide approximately $1.0 billion of working capital funding. At June 30, 2013 and September 30, 2012, a total of $142.0 million and $310.9 million was outstanding under our commercial paper program.
Regulated Operations
We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $989 million of working capital funding, including a five-year $950 million unsecured facility, a $25 million unsecured facility and a $14 million unsecured revolving credit facility, which is used primarily to issue letters of credit. The $25 million facility was renewed on April 1, 2013. Due to outstanding letters of credit, the total amount available to us under our $14 million revolving credit facility was $8.2 million at June 30, 2013.
In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH, which bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or

21



(ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2013.
Nonregulated Operations
Prior to December 5, 2012, Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, had a three-year $200 million committed revolving credit facility, expiring in December 2014, with a syndicate of third-party lenders with an accordion feature that could increase AEM’s borrowing capacity to $500 million. The credit facility was primarily used to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. This facility was collateralized by substantially all of the assets of AEM and was guaranteed by AEH. AEM terminated the committed revolving credit facility on December 5, 2012, to reduce external credit expense. AEM incurred no penalties in connection with the termination. This facility was replaced with two $25 million, 364-day bilateral credit facilities, one of which is a committed facility. These facilities are used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $38.6 million at June 30, 2013.
AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to the greater of (i) the one-month LIBOR rate plus 3.00 percent or (ii) the rate for AEM’s borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2013.
Shelf Registration
On March 28, 2013, we filed a registration statement with the SEC to issue, from time to time, up to $1.75 billion in common stock and/or debt securities available for issuance, which replaced our registration statement that expired on March 31, 2013. As of June 30, 2013, $1.75 billion was available under the shelf registration statement.
Debt Covenants
The availability of funds under our regulated credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At June 30, 2013, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 52 percent. In addition, both the interest margin and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.
In addition to these financial covenants, our credit facilities and public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers.
Additionally, our public debt indentures relating to our senior notes and debentures, as well as our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.
We were in compliance with all of our debt covenants as of June 30, 2013. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

8.    Earnings Per Share
Since we have non-vested share-based payments with a nonforfeitable right to dividends or dividend equivalents (referred to as participating securities), we are required to use the two-class method of computing earnings per share. The Company’s non-vested restricted stock units, for which vesting is predicated solely on the passage of time granted under our 1998 Long-Term Incentive Plan, are considered to be participating securities. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three and nine months ended June 30, 2013 and 2012 are calculated as follows:

22



 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
 
 
 
 
 
 
 
Income from continuing operations
$
33,474

 
$
28,014

 
$
223,162

 
$
192,482

Less: Income from continuing operations allocated to participating securities
91

 
116

 
760

 
808

Income from continuing operations available to common shareholders
$
33,383

 
$
27,898

 
$
222,402

 
$
191,674

Basic weighted average shares outstanding
90,603

 
90,118

 
90,497

 
90,131

Income from continuing operations per share — Basic
$
0.37

 
$
0.31

 
$
2.46

 
$
2.13

 
 
 
 
 
 
 
 
Basic Earnings Per Share from discontinued operations
 
 
 
 
 
 
 
Income from discontinued operations
$
5,294

 
$
3,118

 
$
12,496

 
$
16,268

Less: Income from discontinued operations allocated to participating securities
14

 
13

 
43

 
68

Income from discontinued operations available to common shareholders
$
5,280

 
$
3,105

 
$
12,453

 
$
16,200

Basic weighted average shares outstanding
90,603

 
90,118

 
90,497

 
90,131

Income from discontinued operations per share — Basic
$
0.06

 
$
0.03

 
$
0.14

 
$
0.18

Net income per share — Basic
$
0.43

 
$
0.34

 
$
2.60

 
$
2.31


 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands, except per share amounts)
Diluted Earnings Per Share from continuing operations
 
 
 
 
 
 
 
Income from continuing operations available to common shareholders
$
33,383

 
$
27,898

 
$
222,402

 
$
191,674

Effect of dilutive stock options and other shares

 

 
5

 
4

Income from continuing operations available to common shareholders
$
33,383

 
$
27,898

 
$
222,407

 
$
191,678

Basic weighted average shares outstanding
90,603

 
90,118

 
90,497

 
90,131

Additional dilutive stock options and other shares
947

 
875

 
948

 
875

Diluted weighted average shares outstanding
91,550

 
90,993

 
91,445

 
91,006

Income from continuing operations per share — Diluted
$
0.36

 
$
0.31

 
$
2.43

 
$
2.10

 
 
 
 
 
 
 
 
Diluted Earnings Per Share from discontinued operations
 
 
 
 
 
 
 
Income from discontinued operations available to common shareholders
$
5,280

 
$
3,105

 
$
12,453

 
$
16,200

Effect of dilutive stock options and other shares

 

 

 

Income from discontinued operations available to common shareholders
$
5,280

 
$
3,105

 
$
12,453

 
$
16,200

Basic weighted average shares outstanding
90,603

 
90,118

 
90,497

 
90,131

Additional dilutive stock options and other shares
947

 
875

 
948

 
875

Diluted weighted average shares outstanding
91,550

 
90,993

 
91,445

 
91,006

Income from discontinued operations per share — Diluted
$
0.06

 
$
0.03

 
$
0.14

 
$
0.18

Net income per share — Diluted
$
0.42

 
$
0.34

 
$
2.57

 
$
2.28


23



There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2013 and 2012 as their exercise price was less than the average market price of the common stock during those periods.
Share Repurchase Program
We did not repurchase any shares during the nine months ended June 30, 2013 as part of our 2011 share repurchase program. For the nine months ended June 30, 2012, we repurchased and retired 387,991 shares for an aggregate value of $12.5 million as part of the program.

9.     Interim Pension and Other Postretirement Benefit Plan Information
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and nine months ended June 30, 2013 and 2012 are presented in the following table. Most of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense. On April 1, 2013, due to the retirement of certain executives, we recognized a curtailment loss of $3.2 million associated with our Supplemental Executive Benefit Plan and revalued the net periodic pension cost for the remainder of fiscal 2013. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective April 1, 2013, to 4.21 percent, which will reduce our net periodic pension cost by approximately $0.1 million for the remainder of the fiscal year. All other actuarial assumptions remained the same.
 
Three Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
5,194

 
$
4,297

 
$
4,700

 
$
4,089

Interest cost
6,019

 
6,677

 
3,241

 
3,465

Expected return on assets
(5,739
)
 
(5,368
)
 
(997
)
 
(651
)
Amortization of transition asset

 

 
271

 
377

Amortization of prior service cost
(35
)
 
(35
)
 
(363
)
 
(362
)
Amortization of actuarial loss
5,432

 
4,142

 
1,049

 
662

Curtailment
3,161

 

 

 

Net periodic pension cost
$
14,032

 
$
9,713

 
$
7,901

 
$
7,580

 
Nine Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
15,599

 
$
12,893

 
$
14,100

 
$
12,265

Interest cost
18,067

 
20,032

 
9,723

 
10,396

Expected return on assets
(17,216
)
 
(16,105
)
 
(2,991
)
 
(1,955
)
Amortization of transition asset

 

 
811

 
1,133

Amortization of prior service cost
(106
)
 
(106
)
 
(1,088
)
 
(1,087
)
Amortization of actuarial loss
16,555

 
12,427

 
3,147

 
1,986

Curtailment
3,161

 

 

 

Net periodic pension cost
$
36,060

 
$
29,141

 
$
23,702

 
$
22,738


24



The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2013 and 2012 are as follows:
 
Supplemental Executive Benefit Plans
 
Pension Benefits
 
Other Benefits
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Discount rate
4.21
%
 
5.05
%
 
4.04
%
 
5.05
%
 
4.04
%
 
5.05
%
Rate of compensation increase
3.50
%
 
3.50
%
 
3.50
%
 
3.50
%
 
N/A

 
N/A

Expected return on plan assets
N/A

 
N/A

 
7.75
%
 
7.75
%
 
4.70
%
 
4.70
%
The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2013. During the first nine months of fiscal 2013, we contributed $21.0 million to our defined benefit plans and we anticipate contributing approximately $12 million during the remainder of the fiscal year.
We contributed $19.5 million to our other post-retirement benefit plans during the nine months ended June 30, 2013. We expect to contribute a total of approximately $5 million to $10 million to these plans during the remainder of the fiscal year.

10.    Commitments and Contingencies
Litigation and Environmental Matters
With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2013.
Kentucky Litigation
Since September 2009, Atmos Energy and two subsidiaries of AEH, Atmos Energy Marketing, LLC (AEM) and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate.
Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases.
During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries.
A hearing was held on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals, appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court of Appeals on January 16, 2012, with our reply brief being filed with the Court of Appeals on March 19, 2012. Oral arguments were held in the case on August 27, 2012.
In an opinion handed down on January 25, 2013, the Court of Appeals overturned the $28.5 million jury verdict returned against the Atmos Entities. In a unanimous decision by a three-judge panel, the Court of Appeals reversed the claims asserted by the landowners and investors/working interest owners. The Court of Appeals concluded that all of such claims that the Atmos Entities appealed should have been dismissed by the trial court as a matter of law. The Court of Appeals let stand the jury verdict on one claim that Atmos Energy and our subsidiaries chose not to appeal, which was a trespass claim. The jury had

25



awarded a total of $10,000 in compensatory damages to one landowner on that claim. The Court of Appeals vacated all of the other damages awarded by the jury and remanded the case to the trial court for a new trial, solely on the issue of whether punitive damages should be awarded to that landowner and, if so, in what amount.
The investors/working interest owners, on February 25, 2013, and the landowners, on March 19, 2013, each filed with the Supreme Court of Kentucky, separate motions for discretionary review of the opinion of the Court of Appeals. We filed a response to the motion filed by the investors/working owners on March 27, 2013 and to the landowners’ motion on April 17, 2013. The decision of the Court of Appeals will not become final until the appellate process is completed. We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter and we will continue to maintain this amount in legal reserves until the appellate process in this case has been completed. We continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.
In addition, in a related matter, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate process and related costs are ongoing. This lawsuit is based upon the indemnification provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. On March 27, 2012 the court denied the motion to dismiss. Since that time, we have continued to be engaged in discovery activities in this case.
Tennessee Business License Tax
Atmos Energy, through its affiliate, AEM, has been involved in a dispute with the Tennessee Department of Revenue (TDOR) regarding sales business tax audits over a period of several years. AEM has challenged the assessment of the business tax. With respect to certain issues, AEM and the TDOR filed competing Partial Motions for Summary Judgment with the Chancery Court. On August 2, 2013, the Chancery Court granted the TDOR's Partial Motion for Summary Judgment and denied AEM's Partial Motion for Summary Judgment.  The Company anticipates a decision by the Chancery Court on the remaining issues in fiscal 2014. AEM has been assessed $6.1 million in business taxes and $3.7 million in penalties and interest for the period from December 2002 through March 31, 2012. We believe the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.
We are a party to other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
Purchase Commitments
AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At June 30, 2013, AEH was committed to purchase 84.9 Bcf within one year, 45.1 Bcf within one to three years and 21.7 Bcf after three years under indexed contracts. AEH is committed to purchase 7.1 Bcf within one year and 0.3 Bcf within one to three years under fixed price contracts with prices ranging from $3.40 to $6.36 per Mcf. Purchases under these contracts totaled $340.9 million and $176.6 million for the three months ended June 30, 2013 and 2012 and $958.2 million and $753.0 million for the nine months ended June 30, 2013 and 2012.
Our natural gas distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
 
Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of June 30, 2013 are as follows (in thousands):

26



2013
$
32,791

2014
237,444

2015

2016

2017

Thereafter

 
$
270,235

Our nonregulated segment maintains long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. There were no material changes to the estimated storage and transportation fees for the nine months ended June 30, 2013.
Regulatory Matters
In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act calls for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission (CFTC) to establish rules and regulations for implementation of many of the provisions of the Dodd-Frank Act. The costs of participating in financial markets for hedging certain risks inherent in our business have been increased as a result of the new legislation and related rules and regulations. We also are subject to additional recordkeeping and reporting obligations with regard to certain of our swap transactions. Although the CFTC and SEC have issued a number of required rules and regulations, we expect additional rules and regulations to be adopted, which should provide further clarity regarding the extent of the impact of this legislation on us.
As of June 30, 2013, rate cases were in progress in our Colorado and Kentucky service areas, an annual rate filing mechanism was in progress in Louisiana and an infrastructure program filing was in progress in Virginia. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.

11.    Concentration of Credit Risk
Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. During the nine months ended June 30, 2013, there were no material changes in our concentration of credit risk.

12.    Segment Information
As discussed in Note 1 above, we operate the Company through the following three segments:
The natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
The regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and
The nonregulated segment, which is comprised of our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
 
Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. We evaluate performance based on net income or loss of the respective operating units.
Income statements for the three and nine month periods ended June 30, 2013 and 2012 by segment are presented in the following tables:

27



 
Three Months Ended June 30, 2013
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
465,982

 
$
26,730

 
$
365,223

 
$

 
$
857,935

Intersegment revenues
1,162

 
47,311

 
56,585

 
(105,058
)
 

 
467,144

 
74,041

 
421,808

 
(105,058
)
 
857,935

Purchased gas cost
227,649

 

 
418,548

 
(104,759
)
 
541,438

Gross profit
239,495

 
74,041

 
3,260

 
(299
)
 
316,497

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
93,490

 
17,035

 
11,034

 
(301
)
 
121,258

Depreciation and amortization
48,368

 
8,676

 
1,085

 

 
58,129

Taxes, other than income
45,686

 
4,287

 
741

 

 
50,714

Total operating expenses
187,544

 
29,998

 
12,860

 
(301
)
 
230,101

Operating income (loss)
51,951

 
44,043

 
(9,600
)
 
2

 
86,396

Miscellaneous income (expense)
268

 
(247
)
 
215

 
(703
)
 
(467
)
Interest charges
25,001

 
8,049

 
392

 
(701
)
 
32,741

Income (loss) from continuing operations before income taxes
27,218

 
35,747

 
(9,777
)
 

 
53,188

Income tax expense (benefit)
11,401

 
12,650

 
(4,337
)
 

 
19,714

Income (loss) from continuing operations
15,817

 
23,097

 
(5,440
)
 

 
33,474

Income from discontinued operations, net of tax

 

 

 

 

Gain (loss) on sale of discontinued operations, net of tax
5,649

 

 
(355
)
 

 
5,294

Net income (loss)
$
21,466

 
$
23,097

 
$
(5,795
)
 
$

 
$
38,768

Capital expenditures
$
114,606

 
$
78,012

 
$
738

 
$

 
$
193,356


28





 
 
Three Months Ended June 30, 2012
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
315,420

 
$
26,551

 
$
234,443

 
$

 
$
576,414

Intersegment revenues
214

 
40,522

 
21,807

 
(62,543
)
 

 
315,634

 
67,073

 
256,250

 
(62,543
)
 
576,414

Purchased gas cost
120,575

 

 
224,829

 
(62,161
)
 
283,243

Gross profit
195,059

 
67,073

 
31,421

 
(382
)
 
293,171

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
82,224

 
16,427

 
7,777

 
(383
)
 
106,045

Depreciation and amortization
50,157

 
7,797

 
1,002

 

 
58,956

Taxes, other than income
42,011

 
3,839

 
774

 

 
46,624

Total operating expenses
174,392

 
28,063

 
9,553

 
(383
)
 
211,625

Operating income
20,667

 
39,010

 
21,868

 
1

 
81,546

Miscellaneous income (expense)
(1,053
)
 
(298
)
 
136

 
(860
)
 
(2,075
)
Interest charges
27,820

 
7,353

 
595

 
(859
)
 
34,909

Income (loss) from continuing operations before income taxes
(8,206
)
 
31,359

 
21,409

 

 
44,562

Income tax expense (benefit)
(3,299
)
 
11,215

 
8,632

 

 
16,548

Income (loss) from continuing operations
(4,907
)
 
20,144

 
12,777

 

 
28,014

Income from discontinued operations, net of tax
3,118

 

 

 

 
3,118

Net income (loss)
$
(1,789
)
 
$
20,144

 
$
12,777

 
$

 
$
31,132

Capital expenditures
$
149,531

 
$
34,191

 
$
2,529

 
$

 
$
186,251


29




 
 
Nine Months Ended June 30, 2013
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
2,035,712

 
$
65,084

 
$
1,100,290

 
$

 
$
3,201,086

Intersegment revenues
3,395

 
131,486

 
150,360

 
(285,241
)
 

 
2,039,107

 
196,570

 
1,250,650

 
(285,241
)
 
3,201,086

Purchased gas cost
1,172,975

 

 
1,200,624

 
(284,123
)
 
2,089,476

Gross profit
866,132

 
196,570

 
50,026

 
(1,118
)
 
1,111,610

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
266,570

 
48,745

 
24,679

 
(1,123
)
 
338,871

Depreciation and amortization
146,059

 
25,756

 
3,073

 

 
174,888

Taxes, other than income
132,029

 
12,513

 
1,813

 

 
146,355

Total operating expenses
544,658

 
87,014

 
29,565

 
(1,123
)
 
660,114

Operating income
321,474

 
109,556

 
20,461

 
5

 
451,496

Miscellaneous income (expense)
2,728

 
(473
)
 
1,791

 
(2,103
)
 
1,943

Interest charges
74,228

 
22,777

 
1,687

 
(2,098
)
 
96,594

Income from continuing operations before income taxes
249,974

 
86,306

 
20,565

 

 
356,845

Income tax expense
94,874

 
30,574

 
8,235

 

 
133,683

Income from continuing operations
155,100

 
55,732

 
12,330

 

 
223,162

Income from discontinued operations, net of tax
7,202

 

 

 

 
7,202

Gain (loss) on sale of discontinued operations, net of tax
5,649

 

 
(355
)
 

 
5,294

Net income
$
167,951

 
$
55,732

 
$
11,975

 
$

 
$
235,658

Capital expenditures
$
391,942

 
$
189,051

 
$
1,480

 
$

 
$
582,473


30





 
 
Nine Months Ended June 30, 2012
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
1,862,053

 
$
66,421

 
$
957,443

 
$

 
$
2,885,917

Intersegment revenues
761

 
115,448

 
113,746

 
(229,955
)
 

 
1,862,814

 
181,869

 
1,071,189

 
(229,955
)
 
2,885,917

Purchased gas cost
1,011,832

 

 
1,028,592

 
(228,857
)
 
1,811,567

Gross profit
850,982

 
181,869

 
42,597

 
(1,098
)
 
1,074,350

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
262,255

 
49,239

 
19,597

 
(1,102
)
 
329,989

Depreciation and amortization
151,042

 
23,240

 
2,460

 

 
176,742

Taxes, other than income
130,232

 
11,538

 
2,400

 

 
144,170

Total operating expenses
543,529

 
84,017

 
24,457

 
(1,102
)
 
650,901

Operating income
307,453

 
97,852

 
18,140

 
4

 
423,449

Miscellaneous income (expense)
(2,327
)
 
(634
)
 
739

 
(1,363
)
 
(3,585
)
Interest charges
84,775

 
22,176

 
1,686

 
(1,359
)
 
107,278

Income from continuing operations before income taxes
220,351

 
75,042

 
17,193

 

 
312,586

Income tax expense
86,282

 
26,864

 
6,958

 

 
120,104

Income from continuing operations
134,069

 
48,178

 
10,235

 

 
192,482

Income from discontinued operations, net of tax
16,268

 

 

 

 
16,268

Net income
$
150,337

 
$
48,178

 
$
10,235

 
$

 
$
208,750

Capital expenditures
$
392,666

 
$
97,182

 
$
7,526

 
$

 
$
497,374

 

31



Balance sheet information at June 30, 2013 and September 30, 2012 by segment is presented in the following tables.

 
June 30, 2013
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
4,646,302

 
$
1,134,633

 
$
60,280

 
$

 
$
5,841,215

Investment in subsidiaries
819,806

 

 
(2,096
)
 
(817,710
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
5,870

 

 
26,109

 

 
31,979

Assets from risk management activities
2,015

 

 
11,996

 

 
14,011

Other current assets
413,030

 
15,941

 
503,007

 
(295,715
)
 
636,263

Intercompany receivables
685,107

 

 

 
(685,107
)
 

Total current assets
1,106,022

 
15,941

 
541,112

 
(980,822
)
 
682,253

Intangible assets

 

 
131

 

 
131

Goodwill
573,550

 
132,422

 
34,711

 

 
740,683

Noncurrent assets from risk management activities
85,467

 

 

 

 
85,467

Deferred charges and other assets
426,179

 
18,380

 
8,490

 

 
453,049

 
$
7,657,326

 
$
1,301,376

 
$
642,628

 
$
(1,798,532
)
 
$
7,802,798

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
2,581,444

 
$
383,895

 
$
435,911

 
$
(819,806
)
 
$
2,581,444

Long-term debt
2,455,593

 

 

 

 
2,455,593

Total capitalization
5,037,037

 
383,895

 
435,911

 
(819,806
)
 
5,037,037

Current liabilities
 
 
 
 
 
 
 
 
 
Current maturities of long-term debt

 

 

 

 

Short-term debt
419,298

 

 

 
(277,300
)
 
141,998

Liabilities from risk management activities
1,094

 

 
3

 

 
1,097

Other current liabilities
446,483

 
9,983

 
137,338

 
(16,319
)
 
577,485

Intercompany payables

 
627,933

 
57,174

 
(685,107
)
 

Total current liabilities
866,875

 
637,916

 
194,515

 
(978,726
)
 
720,580

Deferred income taxes
909,925

 
278,898

 
8,451

 

 
1,197,274

Noncurrent liabilities from risk management activities

 

 
2,064

 

 
2,064

Regulatory cost of removal obligation
360,578

 

 

 

 
360,578

Deferred credits and other liabilities
482,911

 
667

 
1,687

 

 
485,265

 
$
7,657,326

 
$
1,301,376

 
$
642,628

 
$
(1,798,532
)
 
$
7,802,798


32





 
September 30, 2012
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
4,432,017

 
$
979,443

 
$
64,144

 
$

 
$
5,475,604

Investment in subsidiaries
747,496

 

 
(2,096
)
 
(745,400
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
12,787

 

 
51,452

 

 
64,239

Assets from risk management activities
6,934

 

 
17,773

 

 
24,707

Other current assets
546,187

 
11,788

 
404,097

 
(223,056
)
 
739,016

Intercompany receivables
636,557

 

 

 
(636,557
)
 

Total current assets
1,202,465

 
11,788

 
473,322

 
(859,613
)
 
827,962

Intangible assets

 

 
164

 

 
164

Goodwill
573,550

 
132,422

 
34,711

 

 
740,683

Noncurrent assets from risk management activities
2,283

 

 

 

 
2,283

Deferred charges and other assets
417,893

 
24,353

 
6,733

 

 
448,979

 
$
7,375,704

 
$
1,148,006

 
$
576,978

 
$
(1,605,013
)
 
$
7,495,675

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
2,359,243

 
$
328,161

 
$
419,335

 
$
(747,496
)
 
$
2,359,243

Long-term debt
1,956,305

 

 

 

 
1,956,305

Total capitalization
4,315,548

 
328,161

 
419,335

 
(747,496
)
 
4,315,548

Current liabilities
 
 
 
 
 
 
 
 
 
Current maturities of long-term debt

 

 
131

 

 
131

Short-term debt
782,719

 

 

 
(211,790
)
 
570,929

Liabilities from risk management activities
85,366

 

 
15

 

 
85,381

Other current liabilities
526,089

 
12,478

 
90,116

 
(9,170
)
 
619,513

Intercompany payables

 
584,578

 
51,979

 
(636,557
)
 

Total current liabilities
1,394,174

 
597,056

 
142,241

 
(857,517
)
 
1,275,954

Deferred income taxes
789,288

 
220,647

 
5,148

 

 
1,015,083

Noncurrent liabilities from risk management activities

 

 
9,206

 

 
9,206

Regulatory cost of removal obligation
381,164

 

 

 

 
381,164

Deferred credits and other liabilities
495,530

 
2,142

 
1,048

 

 
498,720

 
$
7,375,704

 
$
1,148,006

 
$
576,978

 
$
(1,605,013
)
 
$
7,495,675


33



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of June 30, 2013, the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended June 30, 2013 and 2012, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2013 and 2012. These financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of September 30, 2012, and the related consolidated statements of income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 12, 2012, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2012, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/    ERNST & YOUNG LLP
Dallas, Texas
August 7, 2013

34



Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
INTRODUCTION
The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2012.
Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995
The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of adverse economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of possible future additional regulatory and financial risks associated with global warming and climate change on our business; the concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; the inherent hazards and risks involved in operating our gas distribution business, natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.
OVERVIEW
Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which at June 30, 2013 covered service areas located in eight states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers.
Through our nonregulated businesses, we provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties.

As discussed in Note 12, we operate the Company through the following three segments:
the natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and
the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities.

35



We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.
Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012 and include the following:
Regulation
Unbilled revenue
Financial instruments and hedging activities
Fair value measurements
Impairment assessments
Pension and other postretirement plans
Contingencies
Our critical accounting policies are reviewed periodically by the Audit Committee of our Board of Directors. There were no significant changes to these critical accounting policies during the nine months ended June 30, 2013.
RESULTS OF OPERATIONS
Atmos Energy Corporation is involved in the distribution, marketing and transportation of natural gas. Accordingly, our results of operations are impacted by the demand for natural gas, particularly during the winter heating season, and the volatility of the natural gas markets. Historically, this generally has resulted in higher operating revenues and net income during the period from October through March of each fiscal year and lower operating revenues and either lower net income or net losses during the period from April through September of each fiscal year. As a result of the seasonality of the natural gas industry, our second fiscal quarter has historically been our most critical earnings quarter with an average of approximately 56 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years.
However, we anticipate that rate design changes, implemented upon the completion of our most recent rate cases in our Mid-Tex and West Texas Divisions during the first quarter of fiscal 2013, will change this trend. The rate design approved in these regulatory proceedings includes an increase to the customer base charge and a decrease in the consumption charge applied to customer usage. The effect of this change in rate design allows our rates to be more closely aligned with the natural gas distribution industry standard rate design. In addition, we anticipate these divisions, which represent approximately 50 percent of the operating income for our natural gas distribution segment, will earn their operating income more ratably over the fiscal year as we are now less dependent on customer consumption. Thus, as expected, we experienced a decline in operating income during the first six months of fiscal 2013 when these rates were implemented. However, the decline experienced during the first six months was partially offset by higher operating income in the third fiscal quarter.
Additionally, the seasonality of our business impacts our working capital differently at various times during the year. Typically, our accounts receivable, accounts payable and short-term debt balances peak by the end of January and then start to decline, as customers begin to pay their winter heating bills. Gas stored underground, particularly in our natural gas distribution segment, typically peaks in November and declines as we utilize storage gas to serve our customers.
We reported net income of $38.8 million, or $0.42 per diluted share for the three months ended June 30, 2013 compared with net income of $31.1 million, or $0.34 per diluted share in the prior-year quarter. Excluding the impact of unrealized margins, diluted earnings per share increased $0.16 compared with the prior-year quarter. During the nine months ended June 30, 2013 we earned $235.7 million or $2.57 per diluted share, compared with $208.8 million, or $2.28 per diluted share in the prior-year period. Excluding the impact of unrealized margins, diluted earnings per share increased $0.26 compared with the prior-year period. The quarter-over-quarter increase in net income, excluding unrealized margins, was primarily due to the aforementioned rate design changes in our natural gas distribution Texas service areas combined with increased consumption during the fiscal third quarter. The period-over-period increase reflects higher gross profit attributable to current year rate increases in our Kentucky/Mid-States, Colorado-Kansas, Mississippi and Louisiana divisions, recent rate increases approved in our regulated transmission and storage segment and improved asset optimization margins in our nonregulated segment, coupled with lower interest expense.
We completed the sale of our Georgia natural gas distribution operations on April 1, 2013 to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million. The proposed sale was previously announced on August 8, 2012. In connection with the sale, we recognized a net of tax gain of $5.3 million. Accordingly, the results of operations for this service area are shown in discontinued operations for both periods presented. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. The sale of these three service areas was completed in August 2012. During the nine months ended June 30, 2013, net income from discontinued

36



operations was $12.5 million, or $0.14 per diluted share and includes the $5.3 million gain on sale of substantially all of our assets in Georgia. Net income from discontinued operations was $16.3 million, or $0.18 per diluted share in the prior-year period.
We also took several steps during the nine months ended June 30, 2013 to further strengthen our balance sheet and borrowing capability. In December 2012, we amended our $750 million revolving credit agreement primarily to (i) increase our borrowing capacity to $950 million while retaining the accordion feature that would allow an increase in borrowing capacity up to $1.2 billion and (ii) to permit same-day funding on base rate loans. We also terminated Atmos Energy Marketing’s $200 million committed and secured credit facility and replaced this facility with two $25 million 364-day bilateral facilities, which should result in a decrease in external credit expense incurred in our nonregulated operations. After giving effect to these changes, we have over $1 billion of working capital funding from four committed revolving credit facilities and one noncommitted revolving credit facility.
On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which replaced, on a long-term basis, our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012. The net proceeds of approximately $494 million were used to repay $260 million outstanding under the short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes.

Consolidated Results
The following table presents our consolidated financial highlights for the three and nine months ended June 30, 2013 and 2012:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands, except per share data)
Operating revenues
$
857,935

 
$
576,414

 
$
3,201,086

 
$
2,885,917

Gross profit
316,497

 
293,171

 
1,111,610

 
1,074,350

Operating expenses
230,101

 
211,625

 
660,114

 
650,901

Operating income
86,396

 
81,546

 
451,496

 
423,449

Miscellaneous income (expense)
(467
)
 
(2,075
)
 
1,943

 
(3,585
)
Interest charges
32,741

 
34,909

 
96,594

 
107,278

Income from continuing operations before income taxes
53,188

 
44,562

 
356,845

 
312,586

Income tax expense
19,714

 
16,548

 
133,683

 
120,104

Income from continuing operations
33,474

 
28,014

 
223,162

 
192,482

Income from discontinued operations, net of tax

 
3,118

 
7,202

 
16,268

Gain on sale of discontinued operations, net of tax
5,294

 

 
5,294

 

Net income
$
38,768

 
$
31,132

 
$
235,658

 
$
208,750

Diluted net income per share from continuing operations
$
0.36

 
$
0.31

 
$
2.43

 
$
2.10

Diluted net income per share from discontinued operations
0.06

 
0.03

 
0.14

 
0.18

Diluted net income per share
$
0.42

 
$
0.34

 
$
2.57

 
$
2.28

Our consolidated net income (loss) during the three and nine month periods ended June 30, 2013 and 2012 was earned in each of our business segments as follows:
 
Three Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands)
Natural gas distribution segment from continuing operations
$
15,817

 
$
(4,907
)
 
$
20,724

Regulated transmission and storage segment
23,097

 
20,144

 
2,953

Nonregulated segment
(5,440
)
 
12,777

 
(18,217
)
Net income from continuing operations
33,474

 
28,014

 
5,460

Net income from discontinued operations
5,294

 
3,118

 
2,176

Net income
$
38,768

 
$
31,132

 
$
7,636


37



 
Nine Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands)
Natural gas distribution segment from continuing operations
$
155,100

 
$
134,069

 
$
21,031

Regulated transmission and storage segment
55,732

 
48,178

 
7,554

Nonregulated segment
12,330

 
10,235

 
2,095

Net income from continuing operations
223,162

 
192,482

 
30,680

Net income from discontinued operations
12,496

 
16,268

 
(3,772
)
Net income
$
235,658

 
$
208,750

 
$
26,908

Regulated operations contributed 94 percent to our consolidated net income from continuing operations for the nine months ended June 30, 2013. The following tables reflect the segregation of our consolidated net income (loss) and diluted earnings per share between our regulated and nonregulated operations:
 
Three Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands, except per share data)
Regulated operations
$
38,914

 
$
15,237

 
$
23,677

Nonregulated operations
(5,440
)
 
12,777

 
(18,217
)
Net income from continuing operations
33,474

 
28,014

 
5,460

Net income from discontinued operations
5,294

 
3,118

 
2,176

Net income
$
38,768

 
$
31,132

 
$
7,636

 
 
 
 
 
 
Diluted EPS from continuing regulated operations
$
0.42

 
$
0.17

 
$
0.25

Diluted EPS from nonregulated operations
(0.06
)
 
0.14

 
(0.20
)
Diluted EPS from continuing operations
0.36

 
0.31

 
0.05

Diluted EPS from discontinued operations
0.06

 
0.03

 
0.03

Consolidated diluted EPS
$
0.42

 
$
0.34

 
$
0.08

 
Nine Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands, except per share data)
Regulated operations
$
210,832

 
182,247

 
$
28,585

Nonregulated operations
12,330

 
10,235

 
2,095

Net income from continuing operations
223,162

 
192,482

 
30,680

Net income from discontinued operations
12,496

 
16,268

 
(3,772
)
Net income
$
235,658

 
$
208,750

 
$
26,908

 
 
 
 
 
 
Diluted EPS from continuing regulated operations
$
2.30

 
$
1.99

 
$
0.31

Diluted EPS from nonregulated operations
0.13

 
0.11

 
0.02

Diluted EPS from continuing operations
2.43

 
2.10

 
0.33

Diluted EPS from discontinued operations
0.14

 
0.18

 
(0.04
)
Consolidated diluted EPS
$
2.57

 
$
2.28

 
$
0.29

Natural Gas Distribution Segment
The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.

38




Seasonal weather patterns can also affect our natural gas distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 96 percent of our residential and commercial meters in the following states for the following time periods:
 
 
Kansas, West Texas
October — May
Kentucky, Mississippi, Tennessee, Mid-Tex
November — April
Louisiana
December — March
Virginia
January — December
Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas does include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.
As discussed above, the cost of gas typically does not have a direct impact on our gross profit. However, higher gas costs mean higher bills for our customers, which may adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. However, gas cost risk has been mitigated in recent years through improvements in rate design that allow us to collect from our customers the gas cost portion of our bad debt expense on approximately 75 percent of our residential and commercial margins.
As discussed above, on April 1, 2013, we completed the sale of substantially all of our natural gas distribution operations in Georgia. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. The results of these operations have been separately reported in the following tables as discontinued operations and exclude general corporate overhead and interest expense that would normally be allocated to these operations.
During the first nine months of fiscal 2013, we completed 12 regulatory proceedings, which should result in a $70.5 million increase in annual operating income. The majority of this rate increase related to our Mid-Tex Division, where rates became effective January 1, 2013. The rate design approved in our Mid-Tex Division and West Texas Division regulatory proceedings includes an increase to the base customer charge and a decrease in the commodity charge applied to customer consumption. The effect of this change in rate design allows the Company’s rates to be more closely aligned with utility industry standard rate design. In addition, we anticipate these divisions will earn their operating income more ratably over the fiscal year as we are now less dependent on customer consumption. Therefore, we anticipate operating income earned during the first and second fiscal quarters to be lower than in previous periods while operating income earned during the third and fourth fiscal quarters to be higher than in previous periods. For fiscal 2013, as expected, we experienced a decline in operating income in the first and second fiscal quarters when these rates became effective. However, this decline was partially offset in the third fiscal quarter with higher operating income compared to the prior-year period.


39



Three Months Ended June 30, 2013 compared with Three Months Ended June 30, 2012
Financial and operational highlights for our natural gas distribution segment for the three months ended June 30, 2013 and 2012 are presented below.
 
Three Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands, unless otherwise noted)
Gross profit
$
239,495

 
$
195,059

 
$
44,436

Operating expenses
187,544

 
174,392

 
13,152

Operating income
51,951

 
20,667

 
31,284

Miscellaneous income (expense)
268

 
(1,053
)
 
1,321

Interest charges
25,001

 
27,820

 
(2,819
)
Income (loss) from continuing operations before income taxes
27,218

 
(8,206
)
 
35,424

Income tax expense (benefit)
11,401

 
(3,299
)
 
14,700

Income (loss) from continuing operations
15,817

 
(4,907
)
 
20,724

Income from discontinued operations, net of tax

 
3,118

 
(3,118
)
Gain on sale of discontinued operations, net of tax
5,649

 

 
5,649

Net income (loss)
$
21,466

 
$
(1,789
)
 
$
23,255

Consolidated natural gas distribution sales volumes from continuing operations — MMcf
43,190

 
32,535

 
10,655

Consolidated natural gas distribution transportation volumes from continuing operations — MMcf
29,179

 
29,856

 
(677
)
Consolidated natural gas distribution throughput from continuing operations — MMcf
72,369

 
62,391

 
9,978

Consolidated natural gas distribution throughput from discontinued operations — MMcf

 
3,309

 
(3,309
)
Total consolidated natural gas distribution throughput — MMcf
72,369

 
65,700

 
6,669

Consolidated natural gas distribution average transportation revenue per Mcf
$
0.45

 
$
0.43

 
$
0.02

Consolidated natural gas distribution average cost of gas per Mcf sold
$
5.27

 
$
3.73

 
$
1.54

The $44.4 million quarter-over-quarter increase in natural gas distribution gross profit primarily reflects the following:
$28.6 million increase from rate design changes and rate increases, primarily in the Mid-Tex and West Texas Divisions.
$10.5 million increase due to colder weather experienced across most of our service territories after the weather normalization adjustment period.
The increase in gross profit was partially offset by a $13.2 million increase in operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, primarily due to the following:
$4.8 million increase in labor costs primarily due to less labor capitalized in the current year.
$2.3 million increase in bad debt expense primarily attributable to an increase in revenue arising from the rate design changes and the temporary suspension of active customer collection activities following the implementation of a new customer information system during the current quarter.
$2.6 million increase in pension and postretirement benefit costs.
$1.8 million increase primarily associated with higher line locate activities, pipeline and right-of-way maintenance activities.

Miscellaneous income increased $1.3 million, primarily due to higher income earned from performance-based rate (PBR) mechanisms in our Tennessee service area and the implementation of a new PBR in our Mississippi Division.
Interest charges decreased $2.8 million, primarily from interest deferrals associated with our infrastructure spending activities in Texas.

40



The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the three months ended June 30, 2013 and 2012. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
Three Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands)
Mid-Tex
$
30,457

 
$
5,845

 
$
24,612

Kentucky/Mid-States
5,498

 
1,946

 
3,552

Louisiana
7,543

 
6,880

 
663

West Texas
3,678

 
353

 
3,325

Mississippi
1,634

 
1,785

 
(151
)
Colorado-Kansas
2,076

 
1,466

 
610

Other
1,065

 
2,392

 
(1,327
)
Total
$
51,951

 
$
20,667

 
$
31,284


Nine Months Ended June 30, 2013 compared with Nine Months Ended June 30, 2012
Financial and operational highlights for our natural gas distribution segment for the nine months ended June 30, 2013 and 2012 are presented below.
 
Nine Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands, unless otherwise noted)
Gross profit
$
866,132

 
$
850,982

 
$
15,150

Operating expenses
544,658

 
543,529

 
1,129

Operating income
321,474

 
307,453

 
14,021

Miscellaneous income (expense)
2,728

 
(2,327
)
 
5,055

Interest charges
74,228

 
84,775

 
(10,547
)
Income from continuing operations before income taxes
249,974

 
220,351

 
29,623

Income tax expense
94,874

 
86,282

 
8,592

Income from continuing operations
155,100

 
134,069

 
21,031

Income from discontinued operations, net of tax
7,202

 
16,268

 
(9,066
)
Gain on sale of discontinued operations, net of tax
5,649

 

 
5,649

Net income
$
167,951

 
$
150,337

 
$
17,614

Consolidated natural gas distribution sales volumes from continuing operations — MMcf
242,066

 
217,322

 
24,744

Consolidated natural gas distribution transportation volumes from continuing operations — MMcf
98,608

 
98,374

 
234

Consolidated natural gas distribution throughput from continuing operations — MMcf
340,674

 
315,696

 
24,978

Consolidated natural gas distribution throughput from discontinued operations — MMcf
4,731

 
16,646

 
(11,915
)
Total consolidated natural gas distribution throughput — MMcf
345,405

 
332,342

 
13,063

Consolidated natural gas distribution average transportation revenue per Mcf
$
0.45

 
$
0.44

 
$
0.01

Consolidated natural gas distribution average cost of gas per Mcf sold
$
4.86

 
$
4.70

 
$
0.16

The $15.2 million period-over-period increase in natural gas distribution gross profit primarily reflects the following:
$12.5 million increase in rates in our Kentucky/Mid-States, Colorado-Kansas, Mississippi and Louisiana divisions.
$7.4 million increase due to colder weather, primarily in the Mississippi, Kentucky/Mid-States and Colorado-Kansas divisions.
$4.0 million increase in transportation revenues.

41



These increases were partially offset by a $9.0 million decrease associated with the rate design changes implemented in the Mid-Tex and West Texas divisions in the fiscal first quarter.
The increases in gross profit were partially offset by a $1.1 million increase in operating expenses, primarily due to the following:
$6.6 million increase primarily associated with higher line locate activities, pipeline and right-of-way maintenance activities.
$4.3 million increase in labor costs primarily due to less labor capitalized in the current year.
$2.1 million increase in bad debt expense primarily attributable to an increase in revenue arising from the rate design changes and the temporary suspension of active customer collection activities following the implementation of a new customer information system during the current quarter.
$1.8 million increase in pension and postretirement benefit costs.
These increases were partially offset by:
$5.6 million decrease in legal and other administrative costs.
$5.0 million decrease in depreciation expense due to new depreciation rates approved in the most recent Mid-Tex rate case that went into effect in January 2013.
$2.4 million gain realized on the sale of certain investments.
Miscellaneous income increased $5.1 million, primarily due to due to the completion of a periodic review of our PBR mechanism in our Tennessee service area and the implementation of a new PBR program in our Mississippi Division.

Interest charges decreased $10.5 million, primarily from interest deferrals associated with our infrastructure spending activities in Texas.
The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the nine months ended June 30, 2013 and 2012. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
Nine Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands)
Mid-Tex
$
135,747

 
$
142,595

 
$
(6,848
)
Kentucky/Mid-States
45,700

 
32,053

 
13,647

Louisiana
48,432

 
44,551

 
3,881

West Texas
28,264

 
29,017

 
(753
)
Mississippi
33,072

 
29,454

 
3,618

Colorado-Kansas
27,497

 
23,627

 
3,870

Other
2,762

 
6,156

 
(3,394
)
Total
$
321,474

 
$
307,453

 
$
14,021

Recent Ratemaking Developments
Significant ratemaking developments that occurred during the nine months ended June 30, 2013 are discussed below. The amounts described below represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling.

42



Annual net operating income increases totaling $70.5 million resulting from ratemaking activity became effective in the nine months ended June 30, 2013 as summarized below:
Rate Action
 
Annual Increase  to
Operating Income
 
 
(In thousands)
Rate case filings
 
$
56,700

Infrastructure programs
 
4,206

Annual rate filing mechanisms
 
8,244

Other rate activity
 
1,322

 
 
$
70,472

Additionally, the following ratemaking efforts were in progress during the third quarter of fiscal 2013 but had not been completed as of June 30, 2013.
 
 
 
 
 
 
 
Division
 
Rate Action
 
Jurisdiction
 
Operating Income
Requested
 
 
 
 
 
 
(In thousands)
Colorado-Kansas
 
Rate Case(1)
 
Colorado
 
$
10,891

Kentucky/Mid-States
 
Rate Case
 
Kentucky
 
13,133

Kentucky/Mid-States
 
Infrastructure Replacement
 
Virginia
 
213

Louisiana
 
Rate Stabilization Clause (2)
 
LGS
 
1,570

 
 
 
 
 
 
$
25,807


(1) 
This rate case seeks a multi-year step increase in annual operating income of $4.5 million on January 1, 2014, $2.9 million on July 1, 2014 and $3.5 million on July 1, 2015.
(2) 
In June 2013, the Company accepted the Staff's recommended adjustments and implemented an annual increase to operating income of $0.9 million effective in rates on July 1, 2013.

On July 15, 2013, the Company filed a rate review mechanism (RRM) in our Mid-Tex Division, requesting a net increase in annual operating income of $17.1 million.
Rate Case Filings
A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return to our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes the rate cases that were completed during the nine months ended June 30, 2013.
Division
 
State
 
Increase in Annual
Operating Income
 
Effective
Date
 
 
(In thousands)
2013 Rate Case Filings:
 
 
 
 
 
 
Mid-Tex
 
Texas
 
$
42,601

 
12/04/2012
Kentucky/Mid-States
 
Tennessee
 
7,530

 
11/08/2012
West Texas
 
Texas
 
6,569

 
10/01/2012
Total 2013 Rate Case Filings
 
 
 
$
56,700

 
 
Infrastructure Programs
Infrastructure programs such as the Gas Reliability Infrastructure Program (GRIP) allow natural gas distribution companies the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. As of June 30, 2013, we had infrastructure programs approved in Texas, Kansas, Colorado, Kentucky and Virginia. The following table summarizes our infrastructure program filings with effective dates occurring during the nine months ended June 30, 2013.

43



Division
 
Period End
 
Incremental
Net Utility
Plant
Investment
 
Increase in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
 
(In thousands)
 
 
2013 Infrastructure Programs:
 
 
 
 
 
 
 
 
Colorado-Kansas — Kansas
 
09/2012
 
$
5,376

 
$
601

 
01/09/2013
Kentucky/Mid-States — Georgia(1)
 
09/2011
 
6,519

 
1,079

 
10/01/2012
Kentucky/Mid-States — Kentucky
 
09/2013
 
19,296

 
2,425

 
10/01/2012
Kentucky/Mid-States — Virginia
 
09/2013
 
756

 
101

 
10/01/2012
Total 2013 Infrastructure Programs
 
 
 
$
31,947

 
$
4,206

 
 

(1) 
On April 1, 2013, we completed the sale of our Georgia operations to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. The increase in operating income arising from the implementation of the approved infrastructure program is included as a component of discontinued operations through March 31, 2013.
Annual Rate Filing Mechanisms
As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. As of June 30, 2013 we had annual rate filing mechanisms in our Louisiana and Mississippi service areas and in a majority of the service areas in our Mid-Tex Division. These mechanisms are referred to as the Dallas annual rate review (DARR) and rate review mechanism (RRM) in our Mid-Tex Division, stable rate filings in the Mississippi Division and a rate stabilization clause in the Louisiana Division. Discussions are underway regarding a new rate review mechanism processes in our West Texas Division, as was contemplated by the parties in the settlement of the fiscal 2012 rate case. The following annual rate filing mechanisms were completed during the nine months ended June 30, 2013.
Division
 
Jurisdiction
 
Test Year
Ended
 
Additional
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2013 Filings:
 
 
 
 
 
 
 
 
Mid-Tex
 
City of Dallas
 
9/30/2012
 
$
1,800

 
06/01/2013
Louisiana
 
TransLa
 
9/30/2012
 
2,260

 
04/01/2013
Kentucky/Mid-States
 
Georgia(1)
 
9/30/2013
 
743

 
02/01/2013
Mississippi
 
Mississippi
 
6/30/2012
 
3,441

 
11/01/2012
Total 2013 Filings
 
 
 
 
 
$
8,244

 
 

(1) 
On April 1, 2013, we completed the sale of our Georgia operations to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. The increase in operating income arising from the implementation of new rates is included as a component of discontinued operations through March 31, 2013.
Other Ratemaking Activity
The following table summarizes other ratemaking activity during the nine months ended June 30, 2013:
Division
 
Jurisdiction
 
Rate Activity
 
Additional
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2013 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad Valorem(1)
 
$
1,322

 
02/01/2013
Total 2013 Other Rate Activity
 
 
 
 
 
$
1,322

 
 
 
(1) 
The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas service area’s base rates.

44




Regulated Transmission and Storage Segment
Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline–Texas Division. The Atmos Pipeline–Texas Division transports natural gas to our Mid-Tex Division and third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking arrangements, lending arrangements and sales of excess gas.
Our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Mid-Tex service area. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the markets that we serve, which may influence the level of throughput we may be able to transport on our pipeline. Further, natural gas price differences between the various hubs that we serve could influence customers to transport gas through our pipeline to capture arbitrage gains.
The results of Atmos Pipeline — Texas Division are also significantly impacted by the natural gas requirements of the Mid-Tex Division because it is the primary supplier of natural gas for our Mid-Tex Division.
Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.

Three Months Ended June 30, 2013 compared with Three Months Ended June 30, 2012
Financial and operational highlights for our regulated transmission and storage segment for the three months ended June 30, 2013 and 2012 are presented below.
 
Three Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex transportation
$
47,117

 
$
43,693

 
$
3,424

Third-party transportation
18,122

 
17,281

 
841

Storage and park and lend services
1,412

 
1,484

 
(72
)
Other
7,390

 
4,615

 
2,775

Gross profit
74,041

 
67,073

 
6,968

Operating expenses
29,998

 
28,063

 
1,935

Operating income
44,043

 
39,010

 
5,033

Miscellaneous expense
(247
)
 
(298
)
 
51

Interest charges
8,049

 
7,353

 
696

Income before income taxes
35,747

 
31,359

 
4,388

Income tax expense
12,650

 
11,215

 
1,435

Net income
$
23,097

 
$
20,144

 
$
2,953

Gross pipeline transportation volumes — MMcf
153,216

 
146,170

 
7,046

Consolidated pipeline transportation volumes — MMcf
121,194

 
118,678

 
2,516


The $7.0 million increase in regulated transmission and storage gross profit compared to the prior-year quarter was primarily a result of the GRIP filing approved by the RRC during fiscal 2013. On May 7, 2013, the RRC approved the Atmos Pipeline - Texas (APT) GRIP filing with an annual operating income increase of $26.7 million that went into effect with bills rendered on and after May 7, 2013. GRIP filings increased quarter-over-quarter gross profit by $5.6 million.
On June 30, 2013, APT's annual adjustment mechanism expired. The three-year pilot program, approved in fiscal 2011, annually adjusted regulated rates up or down by 75 percent of the difference between APT’s non-regulated annual revenue and a pre-defined base credit. During the fourth quarter of fiscal 2013, APT will request an extension of the annual adjustment mechanism through November 2017.
Operating expenses increased $1.9 million primarily due to increased pipeline maintenance and right-of-way activities.

45



Nine Months Ended June 30, 2013 compared with Nine Months Ended June 30, 2012
Financial and operational highlights for our regulated transmission and storage segment for the nine months ended June 30, 2013 and 2012 are presented below.
 
Nine Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex transportation
$
130,849

 
$
120,150

 
$
10,699

Third-party transportation
47,440

 
46,529

 
911

Storage and park and lend services
4,484

 
5,157

 
(673
)
Other
13,797

 
10,033

 
3,764

Gross profit
196,570

 
181,869

 
14,701

Operating expenses
87,014

 
84,017

 
2,997

Operating income
109,556

 
97,852

 
11,704

Miscellaneous expense
(473
)
 
(634
)
 
161

Interest charges
22,777

 
22,176

 
601

Income before income taxes
86,306

 
75,042

 
11,264

Income tax expense
30,574

 
26,864

 
3,710

Net income
$
55,732

 
$
48,178

 
$
7,554

Gross pipeline transportation volumes — MMcf
493,721

 
483,360

 
10,361

Consolidated pipeline transportation volumes — MMcf
335,036

 
333,341

 
1,695


The $14.7 million increase in regulated transmission and storage gross profit compared to the prior-year period was primarily a result of the GRIP filings approved by the RRC during fiscal 2012 and 2013. During fiscal 2012, the Commission approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $14.7 million, effective April 2012. On May 7, 2013, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $26.7 million that went into effect with bills rendered on and after May 7, 2013. GRIP filings increased period-over-period gross profit by $13.0 million.

This increase was partially offset by a $3.0 million increase in operating expenses largely attributable to increased depreciation expense as a result of increased capital investments and increased pipeline maintenance and right-of-way activities.
Nonregulated Segment
Our nonregulated activities are conducted through Atmos Energy Holdings, Inc. (AEH), which is a wholly-owned subsidiary of Atmos Energy Corporation and operates primarily in the Midwest and Southeast areas of the United States.
AEH’s primary business is to deliver gas and provide related services by aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering gas to customers at competitive prices. These activities are reflected as gas delivery and related services in the table below.
AEH also earns storage and transportation margins from (i) utilizing its proprietary 21-mile pipeline located in New Orleans, Louisiana to aggregate gas supply for our regulated natural gas distribution division in Louisiana, its gas delivery activities and, on a more limited basis, for third parties and (ii) managing proprietary storage in Kentucky and Louisiana to supplement the natural gas needs of our natural gas distribution divisions during peak periods. Most of these margins are generated through demand fees established under contracts with certain of our natural gas distribution divisions that are renewed periodically and subject to regulatory oversight. These activities are reflected as storage and transportation services in the table below.
AEH utilizes customer-owned or contracted storage capacity to serve its customers. AEH seeks to offset the demand fees paid to contract for storage capacity and to maximize the value of this capacity by selling financial instruments to earn a gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. Margins earned from these activities and the related storage demand fees are reported as asset optimization margins. Certain of these arrangements are with regulated affiliates, which have been approved by applicable state regulatory commissions.

46



Our nonregulated activities are significantly influenced by competitive factors in the industry and general economic conditions. Therefore, the margins earned from these activities are dependent upon our ability to attract and retain customers and to minimize the cost of gas and demand fees paid to contract for storage capacity to offer more competitive pricing to those customers.
Further, natural gas market conditions, most notably the price of natural gas and the level of price volatility affect our nonregulated businesses. Natural gas prices and the level of volatility are influenced by a number of factors including, but not limited to, general economic conditions, the demand for natural gas in different parts of the country, the level of domestic natural gas production and the level of natural gas inventory levels.
Natural gas prices can influence:
The demand for natural gas. Higher prices may cause customers to conserve or use alternative energy sources. Conversely, lower prices could cause customers such as electric power generators to switch from alternative energy sources to natural gas.
Collection of accounts receivable from customers, which could affect the level of bad debt expense recognized by this segment.
The level of borrowings under our credit facilities, which affects the level of interest expense recognized by this segment.
Natural gas price volatility can also influence our nonregulated business in the following ways:
Price volatility influences basis differentials, which provide opportunities to profit from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access.
Price volatility also influences the spreads between the current (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads.
Increased volatility impacts the amounts of unrealized margins recorded in our gross profit and could impact the amount of cash required to collateralize our risk management liabilities.
Although natural gas prices have risen somewhat during the last 12 months, the natural gas marketing industry continues to experience compressed basis differentials and lower spot-to-forward price volatility. Accordingly, while we anticipate continuing to profit on a fiscal year basis from our nonregulated activities, we anticipate this segment will continue to represent less than ten percent of our consolidated results.
Our nonregulated segment manages its exposure to natural gas commodity price risk through a combination of physical storage and financial instruments. Therefore, results for this segment include unrealized gains or losses on its net physical gas position and the related financial instruments used to manage commodity price risk. These margins fluctuate based upon changes in the spreads between the physical and forward natural gas prices. Generally, if the physical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will generally record unrealized losses or lower unrealized gains. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.

47



Three Months Ended June 30, 2013 compared with Three Months Ended June 30, 2012
Financial and operating highlights for our nonregulated segment for the three months ended June 30, 2013 and 2012 are presented below.
 
 
Three Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands, unless otherwise noted)
Realized margins
 
 
 
 
 
Gas delivery and related services
$
5,945

 
$
9,637

 
$
(3,692
)
Storage and transportation services
3,689

 
3,313

 
376

Other
846

 
791

 
55

 
10,480

 
13,741

 
(3,261
)
Asset optimization(1)
2,476

 
14,600

 
(12,124
)
Total realized margins
12,956

 
28,341

 
(15,385
)
Unrealized margins
(9,696
)
 
3,080

 
(12,776
)
Gross profit
3,260

 
31,421

 
(28,161
)
Operating expenses
12,860

 
9,553

 
3,307

Operating income (loss)
(9,600
)
 
21,868

 
(31,468
)
Miscellaneous income
215

 
136

 
79

Interest charges
392

 
595

 
(203
)
Income (loss) from continuing operations before income taxes
(9,777
)
 
21,409

 
(31,186
)
Income tax expense (benefit)
(4,337
)
 
8,632

 
(12,969
)
Income (loss) from continuing operations
(5,440
)
 
12,777

 
(18,217
)
Loss on sale of discontinued operations, net of tax
(355
)
 

 
(355
)
Net income (loss)
$
(5,795
)
 
$
12,777

 
$
(18,572
)
Gross nonregulated delivered gas sales volumes — MMcf
97,388

 
89,682

 
7,706

Consolidated nonregulated delivered gas sales volumes — MMcf
83,341

 
79,658

 
3,683

Net physical position (Bcf)
19.2

 
30.3

 
(11.1
)
 
(1) 
Net of storage fees of $2.3 million and $4.2 million.

Gross profit decreased $28.2 million compared to the prior-year quarter, primarily as a result of a $15.4 million decrease in realized margins and a $12.8 million decrease in unrealized margins. The decrease in realized margins primarily reflects decreased asset optimization margins primarily due to the timing and magnitude of gains realized on the settlement of financial positions in the prior-year quarter. During the first six months of fiscal 2012, Atmos Energy Holdings took advantage of falling natural gas prices by injecting gas into storage and rolling financial positions forward for settlement in the third and fourth quarters of fiscal 2012. The spreads captured as a result of this activity were higher than the spreads captured from current period asset optimization activities. This decrease was partially offset by a $1.9 million decrease in storage fees as non-essential contracts were not renewed and expiring contracts were renewed at lower rates reflecting the current market for storage.
Realized margins for gas delivery and related services decreased $3.7 million primarily due to a decrease in gas delivery per-unit margins from 11 cents per Mcf in the prior-year quarter to 6 cents per Mcf, partially offset by a five percent increase in consolidated sales volumes. The decrease in per-unit margins reflects increased sales to lower margin customers, primarily asset management customers, where the lower delivered margins are recovered through asset optimization services.  These increased sales contributed to our overall increase in consolidated sales volumes.
Unrealized margins decreased $12.8 million.
Operating expenses increased $3.3 million, primarily due to litigation related expenses.

48



Nine Months Ended June 30, 2013 compared with Nine Months Ended June 30, 2012
Financial and operational highlights for our nonregulated segment for the nine months ended June 30, 2013 and 2012 are presented below.
 
 
Nine Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands, unless otherwise noted)
Realized margins
 
 
 
 
 
Gas delivery and related services
$
31,279

 
$
35,021

 
$
(3,742
)
Storage and transportation services
10,806

 
9,953

 
853

Other
2,643

 
2,804

 
(161
)
 
44,728

 
47,778

 
(3,050
)
Asset optimization(1)
(10,625
)
 
(17,039
)
 
6,414

Total realized margins
34,103

 
30,739

 
3,364

Unrealized margins
15,923

 
11,858

 
4,065

Gross profit
50,026

 
42,597

 
7,429

Operating expenses
29,565

 
24,457

 
5,108

Operating income
20,461

 
18,140

 
2,321

Miscellaneous income
1,791

 
739

 
1,052

Interest charges
1,687

 
1,686

 
1

Income from continuing operations before income taxes
20,565

 
17,193

 
3,372

Income tax expense
8,235

 
6,958

 
1,277

Income from continuing operations
12,330

 
10,235

 
2,095

Loss on sale of discontinued operations, net of tax
(355
)
 

 
(355
)
Net income
$
11,975

 
$
10,235

 
$
1,740

Gross nonregulated delivered gas sales volumes — MMcf
306,120

 
307,800

 
(1,680
)
Consolidated nonregulated delivered gas sales volumes — MMcf
265,791

 
270,372

 
(4,581
)
Net physical position (Bcf)
19.2

 
30.3

 
(11.1
)
 
(1) 
Net of storage fees of $11.4 million and $13.7 million.

Gross profit increased $7.4 million compared to the prior-year period primarily as a result of a $3.4 million increase in realized margins and a $4.1 million increase in unrealized margins. The increase in realized margins primarily reflects smaller losses incurred from asset optimization margins.
In the prior-year period, AEH executed a strategy to take advantage of falling natural gas prices by injecting gas into storage to capture incremental physical to forward spread values that were subsequently realized during the fiscal third and fourth quarters of fiscal 2012. As a result, AEH realized significant losses on the settlement of financial positions in the first half of the prior fiscal year. Additionally, in the prior-year period, AEM recorded a $1.7 million charge to write down to market certain natural gas inventory that no longer qualified for fair value hedge accounting.
In the current-year period, AEH experienced smaller realized losses from its asset optimization activities due to more favorable financial trading as market prices declined less in the current-year period against the execution strategy compared to the prior-year period. Additionally, storage fees decreased $2.3 million period over period as non-essential contracts were not renewed and expiring contracts were renewed at lower rates reflecting the current market for storage.
Realized margins for gas delivery, storage and transportation services and other services were $3.1 million less than the prior-year period. The two percent decrease in consolidated sales volumes primarily represents a decrease in industrial sales volumes due to increased competition and power generation sales volumes as coal prices were less expensive than natural gas prices for power generators. The impact of lower sales volumes was compounded by a decrease in per-unit margins from 11 cents per Mcf to 10 cents per Mcf.
Operating expenses increased $5.1 million, primarily due to increased litigation and software support costs, partially offset by reduced employee costs.

49



Miscellaneous income increased $1.1 million primarily due to a gain realized from the sale of a peaking power facility and related assets during the fiscal first quarter.
Liquidity and Capital Resources
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a variety of sources including internally generated funds and borrowings under our commercial paper program and bank credit facilities. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. Finally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.
We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. We also evaluate the levels of committed borrowing capacity that we require. As discussed below, we currently have over $1 billion of capacity from our short-term facilities.
On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which, in effect, replaced our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012, on a long-term basis. The net proceeds of approximately $494 million were used to repay $260 million outstanding under our short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes, as discussed in Note 7.
We believe the liquidity provided by our senior notes and committed credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs and capital expenditure program for the remainder of fiscal 2013.
Cash Flows
Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, prices for our products and services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.

Cash flows from operating, investing and financing activities for the nine months ended June 30, 2013 and 2012 are presented below.
 
Nine Months Ended June 30
 
2013
 
2012
 
Change
 
(In thousands)
Total cash provided by (used in)
 
 
 
 
 
Operating activities
$
509,575

 
$
518,806

 
$
(9,231
)
Investing activities
(432,589
)
 
(501,621
)
 
69,032

Financing activities
(109,246
)
 
(120,898
)
 
11,652

Change in cash and cash equivalents
(32,260
)
 
(103,713
)
 
71,453

Cash and cash equivalents at beginning of period
64,239

 
131,419

 
(67,180
)
Cash and cash equivalents at end of period
$
31,979

 
$
27,706

 
$
4,273

Cash flows from operating activities
Period-over-period changes in our operating cash flows are primarily attributable to changes in net income and working capital changes, particularly within our natural gas distribution segment resulting from the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.
For the nine months ended June 30, 2013, we generated cash flow of $509.6 million from operating activities compared with $518.8 million for the nine months ended June 30, 2012. The $9.2 million decrease in operating cash flows primarily reflects the timing of customer collections due to the change in rate design in our Texas natural gas distribution service areas and vendor payments, including lower gas purchases, partially offset by a $16.2 million reduction in pension and postretirement contributions.
Cash flows from investing activities
In recent years, a substantial portion of our cash resources has been used to fund growth projects in our regulated operations, our ongoing construction program and improvements to information technology systems. Our ongoing construction program enables us to enhance the safety and reliability of the systems used to provide natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines

50



and, more recently, expand our intrastate pipeline network. In executing our current regulatory strategy, we are focusing our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline–Texas Division have rate tariffs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.
For the nine months ended June 30, 2013, cash used for investing activities was $432.6 million, compared with $501.6 million in the prior-year period. The period-over-period decrease reflects the receipt of $153 million from the sale of our Georgia operations. Capital expenditures increased $85.1 million to $582.5 million during the nine months ended June 30, 2012. The increase primarily reflects spending incurred for the Line W and Line WX expansion projects and increased cathodic protection spending in our regulated transmission and storage segment. Capital expenditures for fiscal 2013 are currently expected to range from $790 million to $810 million.
Cash flows from financing activities
    
For the nine months ended June 30, 2013, our financing activities used $109.2 million of cash compared with $120.9 million of cash used in the prior-year period. Current year cash flows from financing activities were significantly influenced by the issuance of $500 million 4.15% 30-year unsecured senior notes on January 11, 2013. We used a portion of the net cash proceeds of $493.8 million to repay a $260 million short-term financing facility executed in fiscal 2012 and to settle, for $66.6 million, three Treasury Locks associated with the issuance and to reduce short-term debt borrowings by $167.2 million.

The following table summarizes our share issuances for the nine months ended June 30, 2013 and 2012.
 
Nine Months Ended 
 June 30
 
2013
 
2012
Shares issued:
 
 
 
1998 Long-Term Incentive Plan
531,372

 
414,778

Outside Directors Stock-for-Fee Plan
1,599

 
1,823

Total shares issued
532,971

 
416,601

The year-over-year increase in the number of shares issued primarily reflects the type of awards that were issued from the 1998 Long-Term Incentive Plan in each period. In the current-year period, employees were issued restricted stock units, for which we issued new shares. In the prior-year period, employees were issued restricted stock awards, which were held in trust and did not require the issuance of new shares. For the nine months ended June 30, 2013 and 2012, we canceled and retired 133,351 and 152,427 shares attributable to federal withholdings on equity awards. For the nine months ended June 30, 2012, we repurchased and retired 387,991 shares through our 2011 share repurchase program.
Credit Facilities
Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business and the level of our capital expenditures. Changes in the price of natural gas, the amount of natural gas we need to supply to meet our customers’ needs and our capital spending activities could significantly affect our borrowing requirements. However, our short-term borrowings typically reach their highest levels in the winter months.
We finance our short-term borrowing requirements through a combination of a $750.0 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders that provide approximately $1.0 billion of working capital funding. As of June 30, 2013, the amount available to us under our credit facilities, net of outstanding letters of credit, was $879.8 million.
Shelf Registration
On March 28, 2013, we filed a registration statement with the United States Securities and Exchange Commission to issue, from time to time, up to $1.75 billion in common stock and/or debt securities available for issuance, which replaced our registration statement that expired on March 31, 2013. As of June 30, 2013, $1.75 billion was available under the shelf registration statement.
Credit Ratings
Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension

51



liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.
Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). As of June 30, 2013, all three ratings agencies maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:
 
S&P
 
Moody’s
 
Fitch
Unsecured senior long-term debt
BBB+
  
Baa1
  
A-
Commercial paper
A-2
  
P-2
  
F-2
A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating is AAA for S&P, Aaa for Moody’s and AAA for Fitch. The lowest investment grade credit rating is BBB- for S&P, Baa3 for Moody’s and BBB- for Fitch. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.
Debt Covenants
We were in compliance with all of our debt covenants as of June 30, 2013. Our debt covenants are described in greater detail in Note 7 to the unaudited condensed consolidated financial statements.
Capitalization
The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of June 30, 2013September 30, 2012 and June 30, 2012:
 
 
June 30, 2013
 
September 30, 2012
 
June 30, 2012
 
(In thousands, except percentages)
Short-term debt(1)
$
141,998

 
2.7
%
 
$
570,929

 
11.7
%
 
$
213,491

 
4.5
%
Long-term debt
2,455,593

 
47.4
%
 
1,956,436

 
40.0
%
 
2,206,420

 
46.2
%
Shareholders’ equity
2,581,444

 
49.9
%
 
2,359,243

 
48.3
%
 
2,354,925

 
49.3
%
Total
$
5,179,035

 
100.0
%
 
$
4,886,608

 
100.0
%
 
$
4,774,836

 
100.0
%
 
(1) 
Short-term debt at September 30, 2012 included $260 million outstanding related to a short-term facility we used to redeem our $250 million 5.125% Senior notes in August 2012. The balance outstanding under this short-term facility was repaid in January 2013.
Total debt as a percentage of total capitalization, including short-term debt, was 50.1 percent at June 30, 2013, 51.7 percent at September 30, 2012 and 50.7 percent at June 30, 2012. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent.

52



Contractual Obligations and Commercial Commitments
Significant commercial commitments are described in Note 10 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2013.

Risk Management Activities
We conduct risk management activities through our natural gas distribution and nonregulated segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases.
In our nonregulated segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the financial instruments being treated as mark to market instruments through earnings.
The following table shows the components of the change in fair value of our natural gas distribution segment’s financial instruments for the three and nine months ended June 30, 2013 and 2012:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Fair value of contracts at beginning of period
$
40,126

 
$
(47,532
)
 
$
(76,260
)
 
$
(79,277
)
Contracts realized/settled
81

 
(351
)
 
2,610

 
(31,888
)
Fair value of new contracts
541

 
1,251

 
1,554

 
874

Other changes in value
45,640

 
(46,227
)
 
158,484

 
17,432

Fair value of contracts at end of period
$
86,388

 
$
(92,859
)
 
$
86,388

 
$
(92,859
)
The fair value of our natural gas distribution segment’s financial instruments at June 30, 2013 is presented below by time period and fair value source:
 
Fair Value of Contracts at June 30, 2013
 
Maturity in Years
 
 
Source of Fair Value
Less
Than 1
 
1-3
 
4-5
 
Greater
Than 5
 
Total
Fair
Value
 
(In thousands)
Prices actively quoted
$
921

 
$
85,467

 
$

 
$

 
$
86,388

Prices based on models and other valuation methods

 

 

 

 

Total Fair Value
$
921

 
$
85,467

 
$

 
$

 
$
86,388

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three and nine months ended June 30, 2013 and 2012:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Fair value of contracts at beginning of period
$
(4,019
)
 
$
(2,574
)
 
$
(15,123
)
 
$
(25,050
)
Contracts realized/settled
(2,193
)
 
(7,066
)
 
10,051

 
24,162

Fair value of new contracts

 

 

 

Other changes in value
1,889

 
5,080

 
749

 
(3,672
)
Fair value of contracts at end of period
(4,323
)
 
(4,560
)
 
(4,323
)
 
(4,560
)
Netting of cash collateral
14,252

 
5,684

 
14,252

 
5,684

Cash collateral and fair value of contracts at period end
$
9,929

 
$
1,124

 
$
9,929

 
$
1,124



53



The fair value of our nonregulated segment’s financial instruments at June 30, 2013 is presented below by time period and fair value source:
 
Fair Value of Contracts at June 30, 2013
 
Maturity in Years
 
 
Source of Fair Value
Less
Than 1
 
1-3
 
4-5
 
Greater
Than 5
 
Total
Fair
Value
 
(In thousands)
Prices actively quoted
$
(2,259
)
 
$
(1,975
)
 
$
(89
)
 
$

 
$
(4,323
)
Prices based on models and other valuation methods

 

 

 

 

Total Fair Value
$
(2,259
)
 
$
(1,975
)
 
$
(89
)
 
$

 
$
(4,323
)
Pension and Postretirement Benefits Obligations
For the nine months ended June 30, 2013 and 2012, our total net periodic pension and other benefits costs were $59.8 million and $51.9 million. A substantial portion of those costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
Our fiscal 2013 costs were determined using a September 30, 2012 measurement date. As of September 30, 2012, interest and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond rates as of September 30, 2011, the measurement date for our fiscal 2012 net periodic cost. Accordingly, we decreased our discount rate used to determine our fiscal 2013 pension and benefit costs to 4.04 percent. The expected return on our pension plan assets remained at 7.75 percent, based on historical experience and the current market projection of the target asset allocation. Accordingly, our fiscal 2013 pension and postretirement medical costs for the nine months ended June 30, 2013 were higher than the prior-year period.
The amounts with which we fund our defined benefit plans are determined in accordance with the Pension Protection Act of 2006 (PPA) and are influenced by the funded position of the plans when the funding requirements are determined on January 1 of each year. For the nine months ended June 30, 2013 we contributed $21.0 million to our defined benefit plans. Based upon the most recent evaluation, we anticipate contributing a total of between $30 million and $40 million to our defined benefit plans in fiscal 2013. Further, we will consider whether an additional voluntary contribution is prudent to maintain certain PPA funding thresholds. For the nine months ended June 30, 2013 we contributed $19.5 million to our postretirement medical plans. We anticipate contributing a total of between $25 million and $30 million to these plans during fiscal 2013.
The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plans are subject to change, depending upon the actuarial value of plan assets in the plans and the determination of future benefit obligations as of each subsequent actuarial calculation date. These amounts will be determined by actual investment returns, changes in interest rates, values of assets in the plans and changes in the demographic composition of the participants in the plans.


54



OPERATING STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for our natural gas distribution, regulated transmission and storage and nonregulated segments for the three and nine month periods ended June 30, 2013 and 2012.
Natural Gas Distribution Sales and Statistical Data — Continuing Operations
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
METERS IN SERVICE, end of period
 
 
 
 
 
 
 
Residential
2,751,599

 
2,792,823

 
2,751,599

 
2,792,823

Commercial
246,286

 
254,603

 
246,286

 
254,603

Industrial
1,502

 
2,168

 
1,502

 
2,168

Public authority and other
9,990

 
10,202

 
9,990

 
10,202

Total meters
3,009,377

 
3,059,796

 
3,009,377

 
3,059,796

 
 
 
 
 
 
 
 
INVENTORY STORAGE BALANCE — Bcf(1)
33.7

 
40.3

 
33.7

 
40.3

SALES VOLUMES — MMcf(2)
 
 
 
 
 
 
 
Gas sales volumes
 
 
 
 
 
 
 
Residential
22,668

 
14,299

 
143,920

 
126,204

Commercial
15,198

 
13,424

 
76,919

 
70,894

Industrial
3,408

 
3,163

 
12,891

 
12,533

Public authority and other
1,916

 
1,649

 
8,336

 
7,691

Total gas sales volumes
43,190

 
32,535

 
242,066

 
217,322

Transportation volumes
32,458

 
30,928

 
106,405

 
101,773

Total throughput
75,648

 
63,463

 
348,471

 
319,095

OPERATING REVENUES (000’s)(2)
 
 
 
 
 
 
 
Gas sales revenues
 
 
 
 
 
 
 
Residential
$
289,363

 
$
185,910

 
$
1,301,264

 
$
1,191,268

Commercial
126,925

 
92,017

 
556,194

 
503,737

Industrial
19,303

 
11,975

 
65,059

 
58,997

Public authority and other
12,970

 
7,493

 
51,120

 
46,492

Total gas sales revenues
448,561

 
297,395

 
1,973,637

 
1,800,494

Transportation revenues
14,253

 
12,744

 
47,486

 
42,273

Other gas revenues
4,330

 
5,495

 
17,984

 
20,047

Total operating revenues
$
467,144

 
$
315,634

 
$
2,039,107

 
$
1,862,814

Average transportation revenue per Mcf(1)
$
0.44

 
$
0.43

 
$
0.45

 
$
0.43

Average cost of gas per Mcf sold(1)
$
5.27

 
$
3.73

 
$
4.86

 
$
4.70

See footnotes following these tables.

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Natural Gas Distribution Sales and Statistical Data — Discontinued Operations
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
Meters in service, end of period

 
146,484

 

 
146,484

Sales volumes — MMcf
 
 
 
 
 
 
 
Total gas sales volumes

 
1,570

 
3,611

 
10,365

Transportation volumes

 
1,739

 
1,120

 
6,281

Total throughput

 
3,309

 
4,731

 
16,646

 
 
 
 
 
 
 
 
Operating revenues (000’s)
$

 
$
18,162

 
$
37,962

 
$
103,107

Regulated Transmission and Storage and Nonregulated Operations Sales and Statistical Data
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
CUSTOMERS, end of period
 
 
 
 
 
 
 
Industrial
750

 
797

 
750

 
797

Municipal
133

 
141

 
133

 
141

Other
432

 
433

 
432

 
433

Total
1,315

 
1,371

 
1,315

 
1,371

NONREGULATED INVENTORY STORAGE
 
 
 
 
 
 
 
BALANCE — Bcf
22.2

 
33.3

 
22.2

 
33.3

REGULATED TRANSMISSION AND
 
 
 
 
 
 
 
STORAGE VOLUMES — MMcf(2)
153,216

 
146,170

 
493,721

 
483,360

NONREGULATED DELIVERED GAS SALES
 
 
 
 
 
 
 
VOLUMES — MMcf(2)
97,388

 
89,682

 
306,120

 
307,800

OPERATING REVENUES (000’s)(2)
 
 
 
 
 
 
 
Regulated transmission and storage
$
74,041

 
$
67,073

 
$
196,570

 
$
181,869

Nonregulated
421,808

 
256,250

 
1,250,650

 
1,071,189

Total operating revenues
$
495,849

 
$
323,323

 
$
1,447,220

 
$
1,253,058

Notes to preceding tables:
 
(1) 
Statistics are shown on a consolidated basis.                                                                                          
(2) 
Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.
RECENT ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the unaudited condensed consolidated financial statements.
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. During the nine months ended June 30, 2013, there were no material changes in our quantitative and qualitative disclosures about market risk.
Item 4.
Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the

56



Company’s disclosure controls and procedures were effective as of June 30, 2013 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
    
During the quarter ended June 30, 2013, we implemented a new customer information system, which required modifications to our existing system of internal control over financial reporting due to technical changes in the accounting software system. The implementation of our new customer information system is part of our continuing effort to enhance the design and documentation of our internal control processes to ensure that our internal control over financial reporting continues to function effectively. Other than such system implementation, there were no changes in our internal control over financial reporting during the third quarter of fiscal 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1.
Legal Proceedings
During the nine months ended June 30, 2013, except as noted in Note 10 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and other matters that were disclosed in Note 13 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. We continue to believe that the final outcome of such litigation and other matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
Item 6.
Exhibits
A list of exhibits required by Item 601 of Regulation S-K and filed as part of this report is set forth in the Exhibits Index, which immediately precedes such exhibits.

57



SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
 
ATMOS ENERGY CORPORATION
               (Registrant)

 
 
By: /s/    BRET J. ECKERT
 
 
 
Bret J. Eckert
Senior Vice President and Chief Financial Officer
(Duly authorized signatory)
Date: August 7, 2013

58



EXHIBITS INDEX
Item 6
 
Exhibit
Number
  
Description
Page Number or
Incorporation by
Reference to
12
  
Computation of ratio of earnings to fixed charges
 
15
  
Letter regarding unaudited interim financial information
 
31
  
Rule 13a-14(a)/15d-14(a) Certifications
 
32
  
Section 1350 Certifications*
 
101.INS
  
XBRL Instance Document
 
101.SCH
  
XBRL Taxonomy Extension Schema
 
101.CAL
  
XBRL Taxonomy Extension Calculation Linkbase
 
101.DEF
  
XBRL Taxonomy Extension Definition Linkbase
 
101.LAB
  
XBRL Taxonomy Extension Labels Linkbase
 
101.PRE
  
XBRL Taxonomy Extension Presentation Linkbase
 
 
*
These certifications, which were made pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report on Form 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

59